An Independent Assessment of Reserves and...

RPS Energy

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An Independent Assessment of Reserves and Resources for the Oza and Atala fields

Hardy Oil Nigeria

Date: March 2010

RPS Energy Oza&Atala Independent Estimate of Reserves and Resources

ECV 1538 i January 2010

Table of Contents 1. EXECUTIVE SUMMARY.................................................................................1

1.1 Oza .......................................................................................................1

1.2 Atala......................................................................................................2

2. OZA.................................................................................................................4

2.1 Geology and Geophysics......................................................................4

2.1.1 Database....................................................................................4

2.1.2 Seismic Interpretation ................................................................4

2.1.3 Depth Conversion ......................................................................4

2.1.4 Detailed Discussion of Structure Maps ......................................5

2.2 Petrophysics .......................................................................................11

2.3 Volumetric Estimates ..........................................................................11

2.3.1 K7.2..........................................................................................11

2.3.2 L2.2 ..........................................................................................12

2.3.3 L2.4 ..........................................................................................13

2.3.4 L2.6 ..........................................................................................13

2.3.5 L7.0 ..........................................................................................14

2.3.6 M5.0 .........................................................................................15

2.4 Reservoir Engineering ........................................................................16

2.4.1 First Phase: Re-start Production from Existing Wells...............17

2.4.2 Second Phase: Drill Additional Production Wells .....................18

2.4.3 Later Developments .................................................................20

2.5 Cost Engineering ................................................................................21

2.6 Economical Analysis ...........................................................................24

2.6.1 Commodity Price and Inflation Assumptions............................24

2.6.2 Oza Fiscal and Related Assumptions ......................................24

2.6.3 Oza Cashflow Sharing Arrangement........................................26

2.6.4 Net Revenue Sharing...............................................................27

2.6.5 Oza Field – Reserves Portion – Hardy’s Net Share of Production and Cashflow .........................................................31

2.6.6 Conclusions (Reserves Portion)...............................................34

3. ATALA ..........................................................................................................35

3.1 Geology and Geophysics....................................................................35

3.1.1 Database..................................................................................35

3.1.2 Seismic Interpretation ..............................................................35


ECV 1538 ii January 2010

3.1.3 Depth Conversion ....................................................................36

3.1.4 Detailed Discussion of Structure Maps ....................................36

3.2 Petrophysics .......................................................................................40

3.3 Volumetric Estimates ..........................................................................41

3.3.1 U1 Reservoir ............................................................................41

3.3.2 U2 Reservoir ............................................................................42

3.3.3 U3 Reservoir ............................................................................42

3.3.4 U4 Reservoir ............................................................................43

3.3.5 U7 Reservoir ............................................................................43

3.4 Reservoir Engineering ........................................................................44

3.4.1 Methodology ............................................................................44

3.4.2 Oil Resources...........................................................................45

3.4.3 Gas Resources ........................................................................46

3.4.4 Other Resources......................................................................47

APPENDIX 1: GLOSSARY OF TERMS AND ABBREVIATIONS ..................49

APPENDIX 2: SEISMIC TIES .........................................................................53


ECV 1538 iii January 2010

List of Figures Figure 2.1: Top Depth K7.2 Structure Map .............................................................6

Figure 2.2: Top Depth L2.2 Structure Map..............................................................6




Figure 2.6: Top Depth M5.0 Oza-1 Area Structure Map .......................................10

Figure 2.7: Top Depth M5.0 Oza-4 Area Structure Map .......................................10

Figure 2.8: Oza-2 Range in Production Declines from the M2.2 and M1.0 Reservoirs...........................................................................................18

Figure 3.1: U1 Structure Depth Map .....................................................................37





Figure 3.6: Atala Production Forecasts for Oil ......................................................46

Figure 3.7: Atala Production Forecasts for Gas ....................................................47

Figure 3.8: Atala U6 reinterpreted top structure map............................................48


ECV 1538 iv January 2010

List of Tables Table 2.1: K7.2 Inputs for Volumetric Estimates..................................................12

Table 2.2: K7.2 Volumetric Estimates..................................................................12

Table 2.3: L2.2 Input for Volumetric Estimates ....................................................12

Table 2.4: L2.2 Volumetric Estimates ..................................................................13







Table 2.11: M5.0 Input for Volumetric Estimates ...................................................16

Table 2.12: M5.0 Oza-1 Area Volumetric Estimates..............................................16

Table 2.13: M5.0 Oza-4 Area Volumetric Estimates..............................................16

Table 2.14: Reserves Summary for Six Oza Reservoirs, being developed in the First Phase of Development................................................................18

Table 2.15: Proposed Completion Summary .........................................................19

Table 2.16: Oza Phase 2 Starts Drilling as of Jan-2011 ........................................19

Table 2.17: Range in Technical Resources by Reservoir, associated with the Second Phase of Development ..........................................................20

Table 2.18: Range in Contingent Resources ‘Development on Hold’ by Reservoir ............................................................................................21

Table 2.19: Cost and Production Forecast for Oza Phase 1 (Reserves Only).......23

Table 2.20: Commodity Price Assumptions ...........................................................24

Table 2.21: USD Inflation Assumptions .................................................................24

Table 2.22: Oza Field – Summary of Main Assumed Fiscal Terms .......................25

Table 2.23: Oza Field – Prior Balances .................................................................25

Table 2.24: Oza Field – State Royalty ...................................................................26

Table 2.25: Oza Field – Overriding Royalty ...........................................................26

Table 2.26: Oza Field – Assumed Split of Tangible / Intangible Costs ..................26

Table 2.27: Oza Field – Summary of Net Revenue Calculation Methodology .......29

Table 2.28: Oza Field – Reserves Portion – P90 Case – Partners’ Net Revenue Interests – Annual...............................................................................30




ECV 1538 v January 2010

Table 2.31: Oza Field – Reserves Portion – P90 Case – Hardy’s Net Cashflow ...32



Table 2.34: Oza Field – Reserves Portion – Key Volumetric Outcomes................34

Table 2.35: Oza Field – Reserves portion – NPV Net to Hardy at various Discount Rates ...................................................................................34

Table 2.36: Oza Field – Reserves Portion – Key Dates.........................................34

Table 3.1: U1 Input for Volumetric Estimates ......................................................41

Table 3.2: U1 Volumetric Estimates (mid case)...................................................41


Table 3.4: U2 Volumetric Estimates (mid case)...................................................42


Table 3.6: U3 Volumetric Estimates.....................................................................43





Table 3.11: Atala Contingent Resources (Oil) ‘Development Pending’..................45

Table 3.12: Atala Contingent Resources (Gas) ‘Development Pending’................47


ECV 1538 1 January 2010

1. EXECUTIVE SUMMARY

RPS Energy was asked to assess independently the reserves and resources for two Nigerian marginal fields, Oza and Atala and the value to resources, for which a development plan exists. Both fields have a number of reservoirs and initially the volumetric estimates were critically reviewed and where needed adjusted. After this, production forecasts were updated by either simulation efforts (for the Reserves part) or by decline curve analysis. After a critical review of the corresponding development costs, an economical valuation. Below, a more detailed summary is given for each field separately.

1.1 Oza The Oza field is located in the OML-11 concession and contains oil and gasbearing reservoirs. Four wells were drilled in the field and production from three wells took place between 1960 and 1983. Hardy Oil and its partner Millenium Oil and Emerald Energy Resources plan to re-develop the field in two phases. The first phase is well under way and consists of re-starting production from the Oza-1, -2 and -4 wells, including additional perforations of reservoirs, which are currently not producing. After volumetric review, the available simulation models for the K7.2, L7.0 and M5.0 reservoirs were updated and forecasts were generated. Production forecasts for the M1.0 and M2.2 reservoirs, accessed via Oza-2, have been generated with decline curve analysis. Production is assumed to commence as of April 2010. The resulting technical reserves (gross) for six reservoirs can be summarised by:

Reservoir P90 P50 P10

K7.2 0.45 0.88 2.04L7.0 0.53 0.88 1.03M1.0/M2.2 (OZA-2) 0.08 0.10 0.12M5.0 (OZA-1) 0.09 0.20 0.49M5.0 (OZA-4) 0.77 1.15 1.30Total 1.92 3.21 4.971) Reserves based on 10 bbl/d cut-off per well before economic limit test

Technical1) Reserves (MMbbl)

A quick cost review was performed prior to economical analysis. After an economic limit test and taking Hardy Oil’s net revenue interest in the field (after royalty), the following reserve range and corresponding value can be quoted for the first phase of the development:



P90 P50 P10

Gross Reserves (Technical) (MMbbl) 1.92 3.21 4.97Gross Reserves (Economical) (MMbbl) 1.85 3.12 4.92Net Reserves to Hardy Oil (Economical) (MMbbl) 0.19 0.41 0.74

NPV10 to Hardy Oil (1.1.2010) (MM USD) 6.10 11.46 19.27Note: Net reserves are after royalty

Reserves and Valuation Summary for Oza Phase 1

During the second phase of development for Oza, up to seven additional wells will be drilled. This phase is however less well defined whilst budgets are not final and depend to some extent on the results of the first phase, expected by 3Q10. The resources, associated with this second development phase in Oza are therefore categorised as Contingent Resources ‘Development Pending’ and are likely to be materialised as Reserves during 2010, when additional data become available and budgets will be finalised. Key data in this respect are production performance of the newly perforated K7.2 and L7.0 and PVT data from M5.0 (Oza-1). After a volumetric review, the production forecasts, generated by modelling or decline curves were adjusted for this second phase. The resulting technical resources for this second phase can be summarised as:

Technical Contingent Resources 'Development on Hold' (MMbbl)Reservoir 1C 2C 3C

K7.2 0.13 0.21 0.42L2.2 0.04 0.10 0.17L2.4 1.28 1.63 2.13L2.6 1.59 2.12 2.54L7.0 1.79 2.33 3.01M5.0 (OZA-1) 0.00 0.05 0.04M5.0 (OZA-4) 0.06 0.15 0.19Total 4.89 6.59 8.50Note: Based on 10 bopd cut-off per well

Additional contingent resources exist for Oza, but no development plan is available. RPS Energy estimates around 1.8 MMbbl gross resources (‘Development on Hold’) can be recovered from other oil and gas-bearing reservoirs. Further upside exists in prospective resources (at least 0.2 MMbbl gross but unrisked) and drainage from reservoirs extending outside the acreage held be Hardy Oil, Millenium and Emerald.

1.2 Atala The Atala field is located in OML46 and was discovered by the Atala-1 well. After log evaluation, several reservoirs were found to be oil and gas bearing, but no production tests were carried out. Hardy Oil foresees future development of five reservoirs by 2012 by two wells and one gas disposal well, after testing Atala-1



during 2010. Initially 3 oil bearing reservoirs will be developed and after 12 years two more gas bearing reservoirs. Volumetrics were verified by RPS Energy, which necessitated several re-interpretations of the seismic. Forecasts and costs were critically reviewed and adjusted where necessary. This resulted in the following technical contingent resources (‘Development Pending’) for Atala (gross):

Reservoir 1C 2C 3C

U1 0.77 1.26 1.79U2 1.02 1.64 2.37U3 0.35 0.59 0.81U4 1.62 2.48 3.78U7 0.25 0.35 0.57

Total 4.01 6.32 9.32Note: Technical values, cut off at 10 bopd per well

Atala - Estimated Oil Resources

Resources (MMbbl)

1C 2C 3CDevelopment Pending

U3 4.5 6.0 6.0U7 49.2 61.5 73.8

Total 53.7 67.5 79.8Development on Hold

U6 150 N.A N.ANote: N.A = Not Assessed by RPS

Atala - Estimated Gas Resources

Resources (Bscf)

Additional contingent resources for Atala can be found in four other Atala reservoirs, but since, no development has been planned as yet, these resources can only be categorised as Contingent Resources ‘Development on Hold’. RPS Energy did independently verify the largest of these reservoirs (U6.0), see Table above. It is envisaged that after testing and data gathering of Atala-1 and potential adjustments to the development plan, most of these resources can move to the ‘Reserves’ category.



2. OZA

Oza is located in onshore Nigeria in the SPDC operated OML11 block in the southwestern part of Abia State1. The Oza concession area is ~20 sq km and contains a number of faults, providing structures for hydrocarbon accumulation. The Oza field is contained in sands of the Agbada Formation and alternate shales provide a seal. The underlying Akata Shale is the main source rock in the region. A more detailed description can be found in ref. 1.

2.1 Geology and Geophysics

2.1.1 Database Hardy has provided RPS Energy the following database for the Oza field: • 3D seismic in Landmark™ project with wells, well picks and horizons K7.0, L2.6,

L7.0 and M5.0 interpreted. • Top and base depth grids for horizons L2.2, L2.4, L2.6, L7.0, L9.0, M5.0, K7.0

and K7.2. • Time grids for horizons K7.0, L2.6, L7.0 and M5.0. • Fault files for each horizon. • Deviation surveys for wells Oza-1, Oza-2, Oza-3 and Oza-4. • Tops for each well. • Checkshot survey for Oza-2.

2.1.2 Seismic Interpretation A 3D seismic survey covers ~140 sq km including the Oza concession block. Seismic interpretation within the same fault block as the wells is good. Seismic reflectors at the L2.5 and M5.0 level are not as clear as those at the L7.0 and K7.0 level. Seismic interpretation confidence decreases away from well control and where correlation across faults takes place. Hardy’s depth maps agree with the observed depth picks in the wells with the exception of a few points where there is a difference > ±20ft (see appendix 2: SEISMIC TIES).

2.1.3 Depth Conversion Depth conversion was carried out using the checkshot survey from Oza-2 due to the non-availability of the velocity volume of the 3D data. Velocity gradients were used from the checkshot data and further constrained by using the corresponding depth picks in the wells. Hardy’s confidence in the resulting depth maps is high around the

1 Draft Field Development Plan Phase 1, Millenium Oil and Gas Company Ltd. September 2009



wells and decreases away from the wells. Hardy’s depth maps match the well tops and RPS noticed that the structures are broadly similar in both the verified time-maps and Hardy’s depth maps. RPS has therefore used these maps to calculate GRV. Horizons K7.2, L2.2 and L2.4 were not interpreted in the Landmark™ project: L2.2 and L2.4 are derived from interpreted horizon L2.6 and K7.2 is isopached from interpreted horizon K7.0 by adding 82ft.

2.1.4 Detailed Discussion of Structure Maps

2.1.4.1 K7.2 K7.2 was not interpreted in Landmark™ and therefore the depth map is derived by adding 82ft to the K7.0 depth map. Pay is calculated in Oza-1. No pay is calculated by Hardy in Oza-3 and Oza-4 which are close to the main NW-SE trending fault and down-dip from Oza-1. K7.2 has not produced or been tested. K7.2 is a 4-way dip closure in the P90 case and a 3-way dip closure against a NW/SE striking fault in the P50 and P10 cases (Figure 2.1). Hardy’s depth grids do not cover the entire structure and contingent resources lie outside of the Oza concession block. RPS has fitted a polygon around the structure to exclude western prospective resources and contingent resources outside the concession block in the volumetric calculations.

2.1.4.2 L2.2 L2.2 is not interpreted in the Landmark™ project and the depth map is created from horizon L2.6. Pay is calculated in Oza-1, yet downdip wells Oza-3 and Oza-4 on the same fault block (albeit close to the fault) have no pay. An OWC of 6176 ftTVDSS is estimated from petrophysics carried out by Hardy. L2.2 has not produced or been tested. L2.2 consists of two small 4-way dip closures and a large 3-way dip structure (Figure 2.2). The large structure to the east is not closed within the Oza concession area.



Figure 2.1: Top Depth K7.2 Structure Map

Figure 2.2: Top Depth L2.2 Structure Map

OWC 6176 ft

Polygon

P90 5829 ft

Polygon

P50 5831 ftP10 5850 ft

OWC



2.1.4.3 L2.4 L2.4 is not interpreted in the Landmark™ project and the depth map is created from the L2.6 horizon. Pay is calculated in Oza-1 and none is found in downdip wells Oza-3 and Oza-4, albeit that they are located close to the downdip fault. An OWC of 6242 ftTVDSS is estimated from petrophysics carried out by Hardy. L2.4 has not produced or been tested. L2.4 consists of a number of highs with dip closure and fault closure (Figure 2.3). The structure to the east is not closed within the Oza concession area.


2.1.4.4 L2.6 L2.6 is interpreted in Landmark™ and was depth converted using the checkshot survey of Oza-2. Pay is calculated in Oza-1 and Oza-4 with 5 ft pay in Oza-3. An OWC of 6350.7 ftTVDSS is estimated from petrophysics carried out by Hardy. L2.6 has not produced or been tested. L2.6 consists of a 4-way dip closure with a small component of fault closure in the western area of the fault block (Figure 2.4). A large structure near the wells contains a number of highs and the main structure is not closed within the Oza concession area.

OWC 6248 ft

Polygon




2.1.4.5 L7.0 L7.0 is interpreted in the Landmark™ project and depth converted using the checkshot survey from Oza-2 and subsequently well tied. Pay is calculated for Oza-3 and Oza-4, but none for down-dip Oza-1. An OWC of 7266 ftTVDSS is estimated from petrophysics carried out by Hardy. L7.0 has not produced or been tested. L7.0 main structure is a 3-way dip closure along a fault (Figure 2.5). Additional prospective resources exist to the west, but spill up-dip to the west away from the Oza concession area.

2.1.4.6 M5.0 M5.0 is interpreted in the Landmark™ project and depth converted using the checkshot survey from Oza-2 and subsequently well tied. The M5.0 pick in the 3D seismic level does not tie with well Oza-2 due to the quality of the seismic at that level. M5.0 has produced from Oza-1 and Oza-4.

OWC 6356 ft

Polygon




M5.0 is interpreted in the Landmark™ project and depth converted using the checkshot survey from Oza-2 and subsequently well tied. The M5.0 pick in the 3D seismic level does not tie with well Oza-2 due to the quality of the seismic at that level. M5.0 has produced from Oza-1 and Oza-4. M5.0 closure is fault controlled and has been split into two structural areas: the Oza-1 area and the Oza-4 area with an E-W fault separating the two structures. The areas have separate OWC. The Oza-1 area has an estimated OWC of 9393 ft TVDSS from Hardy’s petrophysics and is away from the crest of the structure. There is a 3-way dip closure at ~9320 ftTVDSS onto the southern NW-SE trending fault and the E-W trending fault separating Oza-4 (Figure 2.6). The structure spills up to the west out of the Oza concession area. The resulting structure is one which terminates against three different faults and making the majority of the structure filled with hydrocarbons. The Oza-4 area has an estimated OWC of 9328 ftTVDSS from Hardy’s petrophysics. The area is composed of an E-W fault separating the Oza-1 area and 2 NW-SE faults (Figure 2.7). A small WSW-ENE fault can be observed in the SE corner. The Oza-4 structure continues to the SE beyond 3D seismic coverage.

OWC 7266 ft

Polygon



Figure 2.6: Top Depth M5.0 Oza-1 Area Structure Map

Figure 2.7: Top Depth M5.0 Oza-4 Area Structure Map

OWC 9328 ft

Min Polygon

Mode Polygon

OWC 9393 ft

Polygon

Oza-1 area

Oza-1 West



2.2 Petrophysics Petrophysical log evaluation on the four Oza wells was independently verified by RPS Energy. Overall the evaluation approach was considered to be reasonable. A number of comments can be made however: • The estimation of porosity in Oza-1, -2 and -3 is particularly difficult without any

porosity logs. The use of synthesized density-curves in the existing analysis2

could be fraught with dangerous inaccuracies since none of the wells had an actual density log for calibration. The technique is better suited for filling in missing sections of log curves.

• An alternative approximate porosity determination was used, based on a clean sand porosity and shale porosity, obtained from Oza-4, which had porosity logs and correcting for shale content. Overall a reasonable agreement with the reported porosity curves was obtained.

• A single water salinity value was used throughout the reservoirs. Pickett plot evidence, backed up by regional evidence in the Niger delta suggest that water salinity increases with depth. This could overestimate the water saturations. For the deeper reservoirs, the expected water saturations, calculated from the methods and parameters, reported in ref. 2, do not agree with the water saturations results in ref. 1. Despite the fact that the results cannot be reproduced from the input data, the reported water saturations seem reasonable.

• Due to the availability of only old logs, there remains uncertainty on the existence and extent of hydrocarbons in the shallower horizons of Oza-1. In particular the hydrocarbon column of the K7.2 reservoir in Oza-1 is considered uncertain. The 48 ft column, analysed in ref. 2 is considered overly optimistic and in disagreement with the WUT in the K 7.2, observed in Oza-3. The K7.2 OWC was therefore taken as a major uncertainty parameter and varied between 5820-5831-5850 ft TVDSS for respectively the P90-P50-P10 cases, corresponding with an 11-23-42 ft oil column in Oza-1. Note that 5850 ft TVDSS also coincides with the spillpoint contour of the K7.2 high around Oza-1.

2.3 Volumetric Estimates

2.3.1 K7.2 Petrophysics carried out by RPS has determined OWC P90-P50-P10 of 5820-5831-5850 ft TVDSS. Different Sw based on the height of the oil column are considered: above the P90 OWC, Sw is estimated at 43 %. Below the P90 OWC, Sw is estimated at 55% The RPS input parameters for the deterministic estimates of STOIIP are summarised in Table 2.1. An area thickness approach is taken to estimate GRV by using Hardy’s top and base depth maps. A polygon is used to restrain the area for volumetric estimate calculation.

2 Four Well Basic Log Evaluation of Oza Field, Nigeria, HuntWallace report dated 9 June 2008



Unit Shape P90 P50 P10

OWC ft TVDSS Triangular 5820 5831 5850

Net to Gross % Single 100 100 100

Porosity % Single 26 26 26

Sw % Sw/Height 43 43<5820 55 >5820

43<5820 55 >5820

FVF (Boi) rb/stb Normal 1.7 1.6 1.5

Table 2.1: K7.2 Inputs for Volumetric Estimates

The deterministic volumetric estimates of STOIIP are summarised in Table 2.2.

STOIIP (MMstb)

P90 P50 P10 K7.2

6.1 8.9 15.7

Table 2.2: K7.2 Volumetric Estimates

The most likely (P50) figure is substantially lower than the single STOIIP estimate for Hardy oil of 13.8 MMstb, mainly as a result of the different contact assumptions.

2.3.2 L2.2 RPS has used Hardy’s STOIIP input parameters for calculating volumes for L2.2. The input parameters for the stochastic estimates of STOIIP are summarised in Table 2.3. A constant OWC of 6176 ft TVDSS is used from Hardy’s calculations. An area thickness approach is taken to estimate GRV by using Hardy’s top and base depth maps. A polygon is added to exclude western up-dip spills and resources outside the Oza concession area. GRV P90-P50-P10 is 25.9-30.3-34.9 km3 based on area uncertainty of 85-100-115%.

Unit Shape Min P90 P50 P10 Max Mode

Net to Gross % Normal 46.6 60 70 80 93.4 70

Porosity % Normal 21.3 24 26 28 30.7 26

Sw % Normal 6.6 20 30 40 53.4 30

FVF (Boi) rb/stb Normal 1.4 1.5 1.6 1.7 1.8 1.6

Table 2.3: L2.2 Input for Volumetric Estimates

The stochastic volumetric estimates of STOIIP for L2.2 are summarised in Table 2.4.



STOIIP (MMstb)

P90 P50 P10 L2.2

11.3 14.9 19.4

Table 2.4: L2.2 Volumetric Estimates

The Hardy single STOIIP figure amounted 14.6 MMstb.

2.3.3 L2.4 RPS has used Hardy’s STOIIP input parameters for calculating volumes for L2.4. The input parameters for the stochastic estimates of STOIIP are summarised in Table 2.5. A constant OWC of 6242 ft TVDSS is used from Hardy’s calculations. An area thickness approach is taken to estimate GRV by using Hardy’s top and base depth maps. A polygon is added to exclude western up-dip spills. GRV P90-P50-P10 is 27.4-32.1-36.9 km3 based on area uncertainty of 85-100-115%.



Porosity % Normal 22.3 25 27 29 31.7 27

Sw % Normal 6.6 20 30 40 53.4 30




STOIIP (MMstb)

P90 P50 P10 L2.4

12.4 16.4 21.3


The Hardy single STOIIP figure amounted to 16.5 MMstb.

2.3.4 L2.6 RPS has used Hardy’s STOIIP input parameters for calculating volumes for L2.6. The input parameters for the stochastic estimates of STOIIP are summarised in Table 2.7. A constant OWC of 6356 ft TVDSS is used from Hardy’s calculations. An area thickness approach is taken to estimate GRV by using Hardy’s top and base depth maps. A polygon is added to exclude western up-dip spills.



GRV P90-P50-P10 is 33-38.7-44.6 km3 based on area uncertainty of 85-100-115%.



Porosity % Normal 22.3 25 27 29 31.7 27

Sw % Normal 3.6 17 27 37 50.4 27




STOIIP (MMstb)

P90 P50 P10 L2.6

15.7 20.6 26.8



2.3.5 L7.0 RPS has used Hardy’s STOIIP input parameters for calculating volumes for L7.0. The input parameters for the stochastic estimates of STOIIP are summarised in Table 2.9. A constant OWC of 7266 fttVDSS is used from Hardy’s calculations. An area thickness approach is taken to estimate GRV by using Hardy’s top and base depth maps. A polygon is added to exclude western prospects. GRV P90-P50-P10 is 7.7-9-10.3 km3 based on area uncertainty of 85-100-115%.



Porosity % Normal 24.3 27 29 31 33.7 29

Sw % Normal 11.6 25 35 45 58.4 35






STOIIP (MMstb)

P90 P50 P10 L7.0

3.4 4.6 6



2.3.6 M5.0 To start with, RPS has used Hardy’s STOIIP input parameters for calculating volumes for M5.0. A constant OWC of 9393 ft TVDSS is used for the Oza-1 and Oza-1 West areas. However, uncertainty exists as to the GOC in the main fault compartment, as Oza-1 had an OUT of 9367 ft TVDSS and the structure extends substantially updip. A triangular shaped distribution of the GOC P90-P50-P10 as 9350-9275-9200 (top structure) ft TVDSS is taken into volumetric estimation of the Oza-1 area. The input parameters for both areas for the stochastic estimates of STOIIP are summarised in Table 2.11. An area thickness approach is taken to estimate GRV by using Hardy’s top and base depth maps. A polygon is added to the Oza-1 area near the up-dip spill (see Figure 2.6) to exclude the Oza-West area, which is considered as prospective. The Oza West area is further discussed under section 2.4.3.

GRV P90-P50-P10 for the Oza-1 area is 15.2-17.9-20.6 km3 based on area uncertainty of 85-100-115%. GRV P90-P50-P10 for the area west of Oza-1 is 10.2-12-13.9 km3 based on area uncertainty of 85-100-115%. There is only negligible uncertainty to the GOC in the Oza-4 block as Oza-4 is near the crest of the fault block. A constant OWC of 9328 ft TVDSS is used for the Oza-4 area. Polygons are used to obtain the minimum and mode GRV followed by a triangular shape distribution to obtain the maximum GRV. GRV P90-P50-P10 for the Oza-4 area is 24.4-29.5-34.7 km3 based on the minimum and mode polygons (black bounded and pink polygons respectively in Figure 2.7). Atriangular shaped distribution is derived from this to obtain the maximum GRV, which therefore implicitly includes GRV to the SE, outside of the Oza concession block.



Table 2.11: M5.0 Input for Volumetric Estimates

The stochastic volumetric estimates of STOIIP for M5.0 Oza-1 area and the area west of Oza-1 are summarised in Table 2.12.

STOIIP (MMstb)

P90 P50 P10

M5.0 Oza-1 3.7 5.5 7.6

M5.0 West 0.7 1.4 2.5

Table 2.12: M5.0 Oza-1 Area Volumetric Estimates

The stochastic volumetric estimates of STOIIP for M5.0 Oza-4 area are summarised in Table 2.13.

STOIIP (MMstb)

P90 P50 P10 M5.0 Oza-4

7.5 10.2 13.6

Table 2.13: M5.0 Oza-4 Area Volumetric Estimates

Hardy has calculated a single STOIIP figure of 6.5 MMstb for the Oza-1 area, which is substantially different from the RPS figure, which assumes a uncertainty in the GOC. For Oza-4 Hardy calculated a single STOIIP figure of 11.8 MMstb.

2.4 Reservoir Engineering Hardy Oil intends to develop the Oza field in phases1. In the first phase, the existing Oza wells are restarted and will be produced via the neighbouring Isimiri flowstation. Since the re-development is well underway, the resources related to the restart of the existing wells can be classified as reserves. After some months of production, a second phase is planned, consisting of drilling additional wells in the field. The resources associated with production of these new wells are considered as contingent resources, since they are dependent on data gathering and production



Porosity % Normal 19.3 22 24 26 28.7 24

Sw % Normal 16.6 30 40 50 63.4 40

FVF (Boi) rb/stb Normal 1.6 1.7 1.8 1.9 2 1.8



performance of the existing wells as well as the fact that subsurface well locations are not completely finalised.

2.4.1 First Phase: Re-start Production from Existing Wells In the first phase, which is well underway, the existing wells are put back on production as of April 2010: Oza-1: Long string: existing M5.0 reservoir. Short string: Perforate and produce the K7.2 reservoir (Mar’10 workover) Oza-2: Long string: existing M2.2 reservoir Short string: existing M1.0 reservoir

Oza-4: Long string: existing M5.0 reservoir. Short string: Perforate and produce the L7.0 reservoir (Dec’10 workover) Hardy oil provided RPS Energy with a number of Eclipse models. The models required updates for the STOIIP-ranges and more realistic well parameters (too low bottomhole flowing pressures were found in the model: in one occasion only 1000 psia and in another occasion the default (=atmospheric) pressure). The following main changes were applied to the models: • Start date 1 April 2010 and 1 Jan 2011 for the L7.0 • A BHFP limit of 2000 psia • A starting rate of 1000-1500 bopd • An abandonment rate of 10 bbl/d (providing enough tail to determine economic

cutoff) • Changes in reservoir pressures, to allow the use of only one PVT-table for all the

reservoirs The models for the M5.0, K7.2 and L7.0 were used to determine a range in remaining reserves, based on a STOIIP range as descibed in the Geology section. For Oza-2 decline curve analysis was used to determine the remaining reserves (see Figure 2.8) and cut-off at 10 bopd.



Oza-2 Production History and Range of production forecastsM2.2 and M1.0 reservoirs combined

1

10

100

1000

mon

th1

mon

th13

mon

th25

mon

th37

mon

th49

mon

th61

mon

th73

mon

th85

mon

th97

mon

th10

9

mon

th12

1

mon

th13

3

mon

th14

5

mon

th15

7

mon

th16

9

bopd

High CaseMid CaseLow CaseHistoric Oil Production

Figure 2.8: Oza-2 Range in Production Declines from the M2.2 and M1.0 Reservoirs

Table 2.14 summarizes all reserves estimates (cut-off at 10 bbl/d) for the six reservoirs, being developed in the first phase of development:

Reservoir P90 P50 P10

K7.2 0.45 0.88 2.04L7.0 0.53 0.88 1.03M1.0/M2.2 (OZA-2) 0.08 0.10 0.12M5.0 (OZA-1) 0.09 0.20 0.49M5.0 (OZA-4) 0.77 1.15 1.30Total 1.92 3.21 4.971) Reserves based on 10 bbl/d cut-off per well before economic limit test

Technical1) Reserves (MMbbl)

Table 2.14: Reserves Summary for Six Oza Reservoirs, being developed in the First Phase of Development

The corresponding production forecasts are listed in Enclosure 1 together with the cost forecast.

2.4.2 Second Phase: Drill Additional Production Wells In the second phase of development, additional wells are drilled. This will take place as of 2011, when the pipeline from Isimiri to Okoloma gas plant will be operational to curtail gas flaring. The drilling and completion duration of each new well is estimated to be 3 months, with the first well to be ready by Apr’11. In comparison with Hardy’s estimate, the STOIIP and corresponding reserves have been considerably reduced for the K7.2 and M5.0 (Oza-1 block). As a result less wells are required for these reservoirs. Moreover the combination of reservoirs per well, described in Table 17 of



ref. 1 also had to change because of the location of the K7.2 target. An updated completion programme is suggested by RPS-Energy and mentioned in Table 2.15,which also limits the number of completions/well to two.

Table 2.15: Proposed Completion Summary

It should be noted that the additional well in the M5.0 reservoir in the Oza-1 block has an appraisal character, due to the uncertainty of a gascap. This may trigger an additional well in the P10 case for this reservoir, but for valuation only one well has been assumed. With a maximum of two strings per well, more wells are required in the L2 reservoirs to achieve three penetrations than proposed in ref.1, leaving the K7.2 target for one well only. For costing reasons this well has been assumed as a workover of any wells of the wells B, C, D or F rather than a newly drilled well. Based on a Jan’11 start-date, the following notional drilling sequence has been assumed in Table 2.16:

Dec-10 WO Oza-4Jan-11Feb-11Mar-11Apr-11May-11Jun-11Jul-11Aug-11Sep-11Oct-11Nov-11Dec-11Jan-12Feb-12Mar-12Apr-12May-12Jun-12Jul-12Aug-12Sep-12Oct-12

Well E

Well A

Well B

Well G

Well C

Well D

Well F

Notional Drilling Sequence for Oza

Table 2.16: Oza Phase 2 Starts Drilling as of Jan-2011

Incremental forecasts for each of the reservoirs have been generated using simplified Eclipse models and similar cut-off criteria were used for the new wells. The resulting technical resources are listed in Table 2.17 and the corresponding production forecasts are mentioned in Enclosure 2.



Note that the low case for M5.0 does not carry any reserves (unsuccessful appraisal), but costs for the well will be included. It is realised that the STOIIP calculations are carried out within the concession boundary and are subsequently modelled by ECLIPSE. For some reservoirs, a larger recovery may be expected, by draining additional reserves from STOIIP, situated outside the concession boundary. This is in particularly true for the eastern part of the L2 reservoirs. This upside is hard to estimate and has therefore not been taken into account.

Technical Contingent Resources 'Development on Hold' (MMbbl)Reservoir 1C 2C 3C

K7.2 0.13 0.21 0.42L2.2 0.04 0.10 0.17L2.4 1.28 1.63 2.13L2.6 1.59 2.12 2.54L7.0 1.79 2.33 3.01M5.0 (OZA-1) 0.00 0.05 0.04M5.0 (OZA-4) 0.06 0.15 0.19Total 4.89 6.59 8.50Note: Based on 10 bopd cut-off per well

Table 2.17: Range in Technical Resources by Reservoir, associated with the Second Phase of Development

2.4.3 Later Developments Oil has been found in the Oza wells in other reservoirs1 such as L1.0, L3.0 and M1.1, which are currently not scheduled for development. The resources, associated with the oil columns, found in these reservoirs can also be classified as Contigent Resources, but its sub-category is different from the reservoirs for which a development plan exists (see section 2.4.2). RPS Energy would classify these resources as ‘Contingent Resources, Development on Hold’. Although RPS Energy did not independently verify the volumetric estimates for these reservoirs, Hardy’s estimates for these reservoirs are considered reasonable, based on the fact that most of the other reservoirs (in the Reserves and Contingent Resources (pending development) categories) had volumetrics in reasonable agreement with RPS Energy’s estimates. It should also be noted that for the M1.1 reservoir only, Hardy has calculated pay3. Other references1,2 (Hunt Wallace and Eogas, see Table 8 in ref. 1) do not show any pay in the M1.1. A payflag exists in the M1.1 in the Oza-2 CPI in ref. 2 and RPS-Energy agrees that is indeed correct, but not reported. Hardy also mentions potential upside for the M2.2 reservoir, which has produced in Oza-2. Given the limited pay column in Oza-2 and the absence of pay in Oza-3 and

3 Re-evaluation report of Oza Field, Nigeria. G&G Team. Hardy Oil (India) July 2009



Oza-4, RPS-Energy does not see any further upside for the M2.2 reservoir, other than estimated from decline curve analysis of Oza-2 (see Table 2.14). It is noted that a 30% ultimate recovery factor had been applied to the STOIIP figures of the three above mentioned reservoirs. In the light of the simulation work for the other categories and their very small oil columns in relation to their lateral extent, this was seen as excessive. A more appropriate recovery factor of 15% has been assumed by RPS. Only 2C resources are quoted for these ‘Contingent Resources, Development on Hold’ and the results are quoted in Table 2.18.

Reservoir Oil Column 2C STOIIP RF 2C Resources(MMbbl) (MMbbl)

L1.0 9 ft (Oza-1) 1.11 15% 0.17L3.0 12 ft (Oza-1) 7.43 15% 1.11M1.1 14 ft (Oza-2) 1.51 15% 0.23

Total 10.05 1.51

Table 2.18: Range in Contingent Resources ‘Development on Hold’ by Reservoir

Prospective resources are calculated in the M5.0 Oza West structure, west of a near saddle. An unrisked STOIIP of 1.4 MMbbl was calculated for an area up to the concession boundary and using the same petrophysics as the M5.0 Oza-1 block. With a 15% recovery factor this translates in an unrisked resource of 0.2 MMbbl. Additional prospective resources may be present in the western area on L2.4, L2.6 and L7.0, but they were considered riskier than the M5.0 due to the presence of a spillpoint. They have therefore not been quantified any further.

2.5 Cost Engineering Information of the costs, associated with the Oza development can be found in ref.1,but a number of amendments have been made: • The gas pipeline to Okoloma is only ready by 1Q11. In the meantime Hardy oil

assumed flaring in Isimiri during 2010 and believes this can be agreed with the authorities. The costs of the pipeline from Isimiri to Okoloma will need to be borne by the first phase development to allow post-2010 production.

• $1.5 M has been included at Isimiri for tying in the pipeline and general rehabilitation work.

• $7.1 M has been included to purchase gas compression facilities in Isimiri in 2010 to allow gas export to Okaloma. This figure was supplied in a later mail, dated 1 March 2010.

• Cost associated with reopening Oza-1, 2 and -4 were estimated to be $0.5 M per well.



• Facility contingencies were increased from 10% to 20% in line with industry norms and indirect costs were added at 25%.

• Variable Opex was taken at $3.50/bbl and a fixed Opex of $1.25 M p.a. was assumed, only for phase 1.

• Yearly G&A costs of $1.2 M have been assumed. The cost forecast together with the production forecasts are listed in Table 2.19 for the phase 1 development.



RPS EnergyECONOMIC INPUT DATA SHEET

COUNTRY: Nigeria Rev. 7PROSPECT/FIELD: Oza US$MM

RESERVES: 3.17 MMbbls Job No. ECV 1538DEVELOPMENT CONCEPT: Re-generation of small existing oil field 03-Mar-10

Year Year Year Year Year Year Year Year Year Year Year Year Year Year Year Year Year Year Year Year Year YearDESCRIPTION 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 TOTALS

2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030

Pre-development costs 0.27 0.27

Production Facilities at Isimiri 1.50 1.50

6" x 10km Line to Isimiri 0.46 2.35

8" x 5km Line to Okoloma 0.31 1.56 1.87

Tie-in to Okaloma 0.50

Indirects @ 25% 1.48 1.48(Eng,PMT, Ins, etc.)Contingency @ 20% 1.48 1.48

Compression at Isimiri 1) 7.10 7.10(no contingencies added, costs already detailed)

FACILITIES TOTAL 1.03 15.97 17.00

Re-Open Oza-1, 2 and 4 1.50 1.50

Workover Oza 1 and 4 6.00 6.00

DRILLING TOTAL 0.00 7.50 7.50

CAPEX TOTAL 1.03 23.47 24.50Capex/bbl 7.63

Fixed Field Opex 1.25 1.25 1.25 1.25 1.25 1.25 1.25 1.25 1.25 1.25 1.25 1.00 1.00 1.00 1.00 1.00 18.75

Variable Opex ($3.50/bbl) 2) 2.08 3.52 2.15 1.40 0.84 0.49 0.29 0.17 0.09 0.05 0.04 0.03 0.03 0.03 0.02 0.02 11.243.5

G&A 0.17 1.20 1.20 1.20 1.20 1.20 1.20 1.20 1.20 1.20 1.20 1.20 1.20 1.20 1.20 1.20 1.20 19.37

Abandonment Provision 10.00 10.00

OPEX TOTAL 0.17 4.53 5.97 4.60 3.85 3.29 2.94 2.74 2.62 2.54 2.50 2.49 2.23 2.23 2.23 2.22 2.22 10.00 59.36Opex/bbl 18.48

PRODUCTION

Oil-bopd 1632 2756 1679 1093 659 382 227 133 67 40 28 22 21 20 19 18 3.21

Gas-MMscfd 0.00

P50 1632 2756 1679 1093 659 382 227 133 67 40 28 22 21 20 19 18 3210.50P10 2136 3309 2574 1727 1204 773 531 412 340 221 146 99 66 33 22 21 4968.79P90 1426 1756 822 454 285 194 138 91 56 30 3 1918.43

Notes 1) 2010 Compression costs are all post-production2) All other costs, apart from variable OPEX are the same for the P90 and P10 cases

Table 2.19: Cost and Production Forecast for Oza Phase 1 (Reserves Only)



2.6 Economical Analysis

2.6.1 Commodity Price and Inflation Assumptions RPS Energy oil price forecasts are based on the RPS Energy’s mid-case forecast for Brent crude. No differential has been assumed between Oza crude realisations and the Brent price. These prices, in MOD (“money-of-the-day”, or inflated) terms, are shown in Table 2.20, below. The gas prices in Nigeria were obtained from Hardy oil. Prices are assumed to increase at an annual rate of 2.0% (including after 2020), in line with our USD inflation assumptions, shown in Table 2.21, below.

Commodity prices (MOD)

Brent Oza / Atala Atala

Crude Crude Realisation Gas Realisation

Year USD / bbl USD / bbl USD / mscf

2009 68.00 68.00 1.00

2010 73.00 73.00 1.02

2011 80.00 80.00 1.04

2012 85.00 85.00 1.06

2013 89.00 89.00 1.08

2014 91.09 91.09 1.10

2015 92.91 92.91 1.13

2016 94.77 94.77 1.15

2017 96.66 96.66 1.17

2018 98.60 98.60 1.20

2019 100.57 100.57 1.22

2020 102.58 102.58 1.24

Table 2.20: Commodity Price Assumptions

Inflation

Annual USD Price inflation rate 2.00%

Annual USD Cost inflation rate 2.00%

Table 2.21: USD Inflation Assumptions

2.6.2 Oza Fiscal and Related Assumptions Fiscal and related assumptions are shown in Table 2.22, Table 2.23, Table 2.24,Table 2.25 and Table 2.26 below.



Fiscal and related terms – Oza Field

Item Value Tax Deductible?

Hardy Working Interest 20.0% n.a.

Hardy Net Revenue Interest Variable n.a.

Education Tax (% of Assessable Profit) 2.0% Yes

VAT (% addition to Capex and Opex) 5.0% (Yes, via depreciation)

Sustainable Community. Development (SCD) Levy, % of Gross revenue 1.0% Yes

NDDC Levy (% of costs when producing) 3.0% Yes

Capital costs depreciation: straight-line method over the shorter of a) the remaining life of the field or b) X years 5 Yes

Petroleum Profits Tax (PPT) rate 55.0% n.a.

Investment Tax Allowance, % of tangible capex 20.0% Yes

Abandonment provisions (start year)* 2010 Yes

Interest earned on abandonment provisions USD LIBOR, assumed to be 1.15% n.a.

Table 2.22: Oza Field – Summary of Main Assumed Fiscal Terms

(*) Note that annual abandonment provisions are calculated as: [10% x D / t] * (1+r) ^ (t-n) ,

where: • D = development costs • t = expected years of economic field life • r = LIBOR rate – here, assumed to be 1.15%, based on the latest data USD

LIBOR rates available from the British Banking Association’s website • n = particular year of production

Oza Field: Pre-2009 data, balance at 1 January 2009

Pre-2009 cumulative production, mm bbl 0.00

Unused Capital allowances, MOD USD mm 7.00

Unused Tax-loss carry forwards, MOD USD mm (0.50)

Table 2.23: Oza Field – Prior Balances



Oza Field: Royalty to the State

Daily production, bbl Rate

>= <= %

0 5,000 2.5%

5,001 10,000 7.5%

10,001 15,000 12.5%

15,001 25,000 18.5%

25,001 no limit unless renegotiated 18.5%

Table 2.24: Oza Field – State Royalty

Oza Field: Overriding Royalty -

Daily production, bbl Rate

>= <= %

0 2,000 2.5%

2,001 5,000 3.0%

5,001 10,000 5.5%

15,001 no limit unless renegotiated 7.5%

Table 2.25: Oza Field – Overriding Royalty

Cost classification assumptions

Cost category Tangible Intangible

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

Exploration Drilling 50% 50%

Appraisal Drilling 50% 50%

Facilities 90% 10%

Development Drilling 30% 70%

Pipelines 50% 50%

Opex 0% 100%

Table 2.26: Oza Field – Assumed Split of Tangible / Intangible Costs

2.6.3 Oza Cashflow Sharing Arrangement The Working Interests (WIs) of the three Oza Field JV partners are as follows:

• Hardy: 20% • Emerald: 20% • Millennium: 60%

Deriving each partner’s share of volumes, revenue and costs, however, is more complex than merely applying these WIs to the relevant field totals. This is due to the



different capex burdens partners have agreed to carry, and the cost recovery mechanisms they have agreed to implement. These arrangements are stipulated in a series of agreements (hereafter collectively referred to as “the Agreements”), the most recent of which is a Heads of Agreement (HOA) signed 18 December 2009 by the three JV partners and the company Xenergi. (The HOA states that it is valid for 30 days, at which point it is to be superseded by a more detailed agreement; as at 3 March, 2010, however, no such new agreement had been signed, according to Hardy, which has advised to use the terms of the HOA for economic analysis purposes). Our economic analysis is based on our understanding – with guidance from Hardy -- of the terms stipulated in the Agreements. Certain costs have been and are expected to be incurred up to and including the first year of commercial production (2010). We term these costs “Upfront Costs”. They consist of:

• USD 3.3 mm incurred by Hardy before 2009

• USD 3.5 mm incurred by Emerald before 2009

• USD $7.10 mm (in 2009 Real USD terms; or USD 7.24 mm in inflated, money-of-the–day terms) in compression capex, to be incurred by Emerald in 2010, once first commercial production begins

• All field capex from 1 January 2009 until first commercial production begins, to be incurred by Xenergi. We term this capex Xenergi’s “Principal”. (We assume that Xenergi shoulders the capex already incurred, between 1 January 2009 and the HOA signing date of 18 December 2009 HOA, by way of reimbursing the JV for this expenditure).

All other capex is to be funded by three JV partners, pro-rata to their WI’s in the Oza license. Xenergi is to recover its Principal (as defined above) from a share of “Net Revenue” (as defined below). In addition, Xenergi is entitled to receive the following:

• reimbursement for USD 40,000 per month for G&A expenses it agrees to fund before first commercial production (we assume Xenergi will fund this only during the pre-production months – January through the end of March – of 2010)

• a Cost Surcharge equal to 10% of Xenergi’s Principal

• interest on the sum of (Xenergi’s Principal + the Cost Surcharge) at a rate based on NIBOR. Hardy has advised us to assume an annual NIBOR rate of 10.00%, which translates into a quarterly rate of 2.41%.

• a Transaction Cost equal to 10% of Xenergi’s principal a Production Operations Charge (POC). This is equal to 10% of Oza Gross Field Revenue, until whichever of the following events occurs first: a) cumulative Oza field production reaches 2 MMbbl or, b) five years elapse from first commercial production

2.6.4 Net Revenue Sharing The recovery of the aforementioned costs is determined by adjustments to the JV partners’ and Xenergi’s “Net Revenue Interests”, which means their entitlement to



total Oza field “Net Revenue.” As the term is “Net Revenue” is not defined explicitly in the Agreements, we assume, following Hardy’s guidance, that

• total Oza Field “Net Revenue” equals total field net operating cashflow, i.e. sales revenue less all cash costs (including royalties, taxes and miscellaneous levies) except for capex.

• each partner’s comprehensive net cashflow (i.e. what is discounted to arrive

at an NPV of each partner’s economic interest in the field) equals each partner’s share of “Net Revenue” less its share of capex.

The following summarises our assumptions regarding the sharing of Net Revenue, which we base on our reading of the Agreements and Hardy’s guidance.

• 30% of Net Revenue is reserved for the three JV partners’, to be allocated to them according to their respective Working Interests.

• The remaining 70% of Net Revenue is to be made available to Xenergi for the recovery of its Principal and other entitlements (described above) and to Hardy and Emerald for the recovery of their respective Upfront Costs. For any given year during which Xenergi, Hardy and / or Emerald are entitled to funds from this 70% of Net Revenue,

o Xenergi has first call on these funds for repayment of its Principal and other entitlements

o Any funds remaining from the 70% of Net revenue, after Xenergi has received the sums due to it, are to be allocated

� a) 50% to Hardy and 50% to Emerald, until Hardy has recovered its Upfront Costs, and

� b) 0% to Hardy and 100% to Emerald, until Emerald has recovered its Upfront Costs.

o Any funds remaining from this 70% of Net Revenue, after Xenergi, Hardy and Emerald have received the sums due to them, are added to the 30% of Net Revenue reserved for the three JV partners, to be allocated to them according to their respective Working Interests.

We have summarised the method of our Net Revenue allocation calculations in Table 2.27.The partners’ Net Revenue Interests over the economic life of the Reserves portion of the Oza field for each case are shown on annual basis in Table 2.28, Table 2.29, and Table 2.30 below.



Item Index Comment

Total Net Revenue a) = Gross Field Revenue less all cash costs excluding capex

Portion of Net Revenue available for recovery of Upfront Costs & Xenergi’s other entitlements

b) = a) * 70%

Portion of Net Revenue designated for allocation to JV Partners according to their Working Interests

c) = a) - b)

Xenergi recovery of Upfront Costs and receipt of other entitlements d) = Lesser of sums due to Xenergi and

b) Funds remaining, after payments to Xenergi, for recovery of Hardy & Emerald Upfront Costs

e) = b) - d)

Funds available for Hardy's Upfront Cost recovery f) Pre-Hardy recovery: = e) * 50%;

Post-Hardy recovery: = e) * 0% Hardy cost recovery taken g) = Lesser of Hardy Upfront costs and f) Funds available for Emerald's Upfront Cost recovery h) Pre-Hardy recovery: = e) * 50%;

Post-Hardy recovery: = e) * 100%

Emerald cost recovery taken i) = Lesser of Emerald Upfront costs and h)

Funds remaining, after the above payments to Xenergi, Hardy and Emerald

J) = b) - d) - g) - i)

Available Net Revenue to be allocated to JV partners pro-rata to their Working Interests

k) = c) + J)

Hardy Working Interest L) 20%

Emerald Working Interest m) 20% Millennium Working Interest n) 60% Hardy Net Revenue allocated according to its Working Interest o) = L) * k)

Emerald Net Revenue allocated according to its Working Interest p) = m) * k)

Millennium Net Revenue allocated according to its Working Interest Q) = n) * k)

Total Net Revenue due to Xenergi r) = d) Total Net Revenue due to Hardy s) = g) + o)

Total Net Revenue due to Emerald t) = i) + p)

Total Net Revenue due to Millennium u) = Q) Total Net Revenue V) = r) + s) + t) + u); also = a)

Table 2.27: Oza Field – Summary of Net Revenue Calculation Methodology



Oza Reserves -- P90 -- Net revenue interests (annual)

Net revenue Interest Year Xenergi Hardy Emerald Millenium Total 2009 0.0% 0.0% 0.0% 0.0% 0.0% 2010 70.0% 6.0% 6.0% 18.0% 100.0% 2011 70.0% 6.0% 6.0% 18.0% 100.0% 2012 35.7% 23.2% 23.2% 18.0% 100.0% 2013 21.2% 26.7% 31.4% 20.8% 100.0% 2014 19.5% 6.0% 56.5% 18.0% 100.0% 2015 15.1% 6.0% 60.9% 18.0% 100.0% 2016 0.0% 6.0% 76.0% 18.0% 100.0%

Weighted average 54.9% 10.8% 16.0% 18.3% 100.0%

Xenergi fully recovers costs / entitlement in: 1Q 2015 Hardy fully recovers costs in: 4Q 2013

Emerald fully recovers costs in: Does not fully recover costs from funds for this purpose

Table 2.28: Oza Field – Reserves Portion – P90 Case – Partners’ Net Revenue Interests – Annual


Net revenue Interest Year Xenergi Hardy Emerald Millenium Total 2009 0.0% 0.0% 0.0% 0.0% 0.0% 2010 70.0% 6.0% 6.0% 18.0% 100.0% 2011 55.8% 13.1% 13.1% 18.0% 100.0% 2012 15.6% 12.7% 47.2% 24.5% 100.0% 2013 0.0% 20.0% 20.0% 60.0% 100.0% 2014 0.0% 20.0% 20.0% 60.0% 100.0% 2015 0.0% 20.0% 20.0% 60.0% 100.0% 2016 0.0% 20.0% 20.0% 60.0% 100.0% 2017 0.0% 20.0% 20.0% 60.0% 100.0%


Xenergi fully recovers costs / entitlement in: 3Q 2012 Hardy fully recovers costs in: 1Q 2012 Emerald fully recovers costs in: 4Q 2012





Net revenue Interest Year Xenergi Hardy Emerald Millenium Total 2009 0.0% 0.0% 0.0% 0.0% 0.0% 2010 70.0% 6.0% 6.0% 18.0% 100.0% 2011 44.6% 15.3% 19.6% 20.5% 100.0% 2012 0.3% 16.3% 34.3% 49.0% 100.0% 2013 0.0% 20.0% 20.0% 60.0% 100.0% 2014 0.0% 20.0% 20.0% 60.0% 100.0% 2015 0.0% 20.0% 20.0% 60.0% 100.0% 2016 0.0% 20.0% 20.0% 60.0% 100.0% 2017 0.0% 20.0% 20.0% 60.0% 100.0% 2018 0.0% 20.0% 20.0% 60.0% 100.0% 2019 0.0% 20.0% 20.0% 60.0% 100.0% 2020 0.0% 20.0% 20.0% 60.0% 100.0% 2021 0.0% 20.0% 20.0% 60.0% 100.0%


Xenergi fully recovers costs / entitlement in: 1Q 2012 Hardy fully recovers costs in: 4Q 2011 Emerald fully recovers costs in: 2Q 2012


2.6.5 Oza Field – Reserves Portion – Hardy’s Net Share of Production and Cashflow

Hardy’s Net shares of production and cashflow are shown in Table 2.31, Table 2.32 and Table 2.33. below. Hardy’s Net Production is equal to Gross (i.e. total field) value multiplied by Hardy’s Net revenue Interest for a given year.

The same calculation holds true for all items in the cashflow tables (except for Capex after the first year of commercial production, which is calculated as Gross field capex multiplied by Hardy’s Working Interest – but which in the three cases examined is equal to 0.) For reasons of space, however, the Gross cashflow items are not shown. They can be derived by dividing the corresponding net-to-Hardy value by Hardy’s Net Revenue Interest for the year.



Case: Oil Total Facilities Drilling Total Total Aband. Educ. Tax, PPT Total Net Disc. Factor 1 Jan. 2010Oza

Reserves --P90

Production Revenue Capex Capex Royalties Opex Provision NDDC&SDC

(Inc.Tax) Costs Cashflow at 10%

Disc.Disc.

Cashflow

Year mm bbl USD MM USD MM USD MM USD MM USD MM USD MM USD MM USD MM USD MM USD MM Rate USD MM2009 - - - - - - - - - - -2010 0.03 2.28 - - 0.11 0.27 0.03 0.10 0.32 0.84 1.44 0.9535 1.372011 0.04 3.08 - - 0.15 0.31 0.03 0.09 1.22 1.80 1.28 0.8668 1.112012 0.07 5.91 - - 0.30 0.90 0.10 0.18 1.83 3.31 2.60 0.7880 2.052013 0.04 3.93 - - 0.20 0.92 0.12 0.12 0.72 2.07 1.86 0.7164 1.332014 0.01 0.57 - - 0.03 0.20 0.03 0.02 0.01 0.28 0.29 0.6512 0.192015 0.00 0.40 - - 0.02 0.19 0.03 0.01 0.08 0.33 0.07 0.5920 0.042016 0.00 0.29 - - 0.01 0.19 0.03 0.01 0.03 0.27 0.02 0.5382 0.01

Total from2010 0.20 16.45 - - 0.82 2.98 0.35 0.54 4.20 8.89 7.56 6.10

Table 2.31: Oza Field – Reserves Portion – P90 Case – Hardy’s Net Cashflow

Case: Oil Total Facilities Drilling Total Total Aband. Educ.Tax, PPT Total Net Disc.

Factor 1 Jan. 2010Oza

Reserves --P50

Production Revenue Capex Capex Royalties Opex Provision NDDC&SDC

(Inc.Tax) Costs Cashflow at 10%

Disc.Disc.

Cashflow

Year mm bbl USD MM USD MM USD MM USD MM USD MM USD MM USD MM USD MM USD MM USD MM Rate USD MM2009 - - - - - - - - - - -2010 0.04 2.61 - - 0.13 0.29 0.02 0.11 0.48 1.04 1.57 0.9535 1.502011 0.13 10.54 - - 0.58 0.85 0.05 0.31 4.46 6.26 4.28 0.8668 3.712012 0.08 6.62 - - 0.33 0.65 0.05 0.20 2.63 3.86 2.76 0.7880 2.172013 0.08 7.10 - - 0.36 0.87 0.08 0.21 2.55 4.07 3.03 0.7164 2.172014 0.05 4.39 - - 0.22 0.76 0.08 0.13 1.23 2.43 1.96 0.6512 1.282015 0.03 2.59 - - 0.13 0.69 0.08 0.08 0.88 1.87 0.72 0.5920 0.432016 0.02 1.57 - - 0.08 0.66 0.08 0.05 0.39 1.25 0.32 0.5382 0.172017 0.01 0.94 - - 0.05 0.64 0.07 0.03 0.07 0.87 0.06 0.4893 0.03

Total from2010 0.43 36.35 - - 1.87 5.43 0.51 1.13 12.70 21.64 14.70 11.46




Case: Oil Total Facilities Drilling Total Total Aband. Educ. Tax, PPT Total Net Disc. Factor 1 Jan. 2010Oza Reserves --

P10 Production Revenue Capex Capex Royalties Opex Provision NDDC &SDC (Inc. Tax) Costs Cashflow at 10% Disc. Disc. Cashflow

Year mm bbl USD MM USD MM USD MM USD MM USD MM USD MM USD MM USD MM USD MM USD MM Rate USD MM2009 - - - - - - - - - - -2010 0.05 3.41 - - 0.19 0.33 0.02 0.13 0.86 1.53 1.88 0.9535 1.792011 0.18 14.79 - - 0.81 1.12 0.05 0.44 6.41 8.82 5.97 0.8668 5.182012 0.15 13.05 - - 0.72 1.05 0.05 0.38 5.54 7.74 5.31 0.7880 4.192013 0.13 11.22 - - 0.56 1.06 0.06 0.33 4.54 6.55 4.67 0.7164 3.342014 0.09 8.00 - - 0.40 0.92 0.06 0.24 2.99 4.61 3.39 0.6512 2.212015 0.06 5.25 - - 0.26 0.81 0.06 0.16 2.17 3.47 1.78 0.5920 1.052016 0.04 3.68 - - 0.18 0.75 0.06 0.11 1.41 2.52 1.16 0.5382 0.622017 0.03 2.91 - - 0.15 0.73 0.06 0.09 1.04 2.06 0.85 0.4893 0.412018 0.02 2.45 - - 0.12 0.72 0.06 0.08 0.81 1.79 0.66 0.4448 0.292019 0.02 1.62 - - 0.08 0.70 0.06 0.05 0.40 1.29 0.33 0.4044 0.132020 0.01 1.09 - - 0.05 0.69 0.05 0.04 0.14 0.98 0.11 0.3676 0.042021 0.01 0.76 - - 0.04 0.62 0.05 0.03 0.01 0.75 0.01 0.3342 0.00

Total from 2010 0.78 68.23 - - 3.57 9.51 0.62 2.08 26.33 42.11 26.12 19.27



ECV1538 34 January, 2010

2.6.6 Conclusions (Reserves Portion) Key volumetric outcomes of our analysis of the Reserves portion of the Oza Field valuation are shown in Table 2.34 below. Note that the Hardy Working Interest (WI) volumes are of indicative interest only, whereas Hardy Net Revenue Interest volumes, net of royalties, are the best indicator of Hardy’s actual economic entitlement. (The difference between WI and Net Revenue Interests is explained in Section 2.6.3).

Item Unit Oza Reserves -- P90

Oza Reserves -- P50

Oza Reserves -- P10

Total field Oil production, gross of royalties mm bbl 1.85 3.12 4.92 Total field Oil production, net of royalties mm bbl 1.76 2.96 4.66 Hardy WI Oil production, gross of royalties mm bbl 0.37 0.62 0.98 Hardy WI Oil production, net of royalties mm bbl 0.35 0.59 0.93 Hardy Net Rev. Int. Oil production, gross of royalties mm bbl 0.20 0.43 0.78 Hardy Net Rev. Int. Oil production, net of royalties mm bbl 0.19 0.41 0.74

Table 2.34: Oza Field – Reserves Portion – Key Volumetric Outcomes

Net present values, as at 1 January 2010 and at various discount rates, of Hardy’s economic interest in the Reserves portion of the Oza Field are shown in Table 2.35 below. Note that in all of our NPV calculations we assume mid-year discounting.

Oza Reserves -- Net present values (1 January 2010) to Hardy by case and discount rate, MOD USD mm Discount Rate Oza Reserves -- P90 Oza Reserves -- P50 Oza Reserves -- P10

0.0% 7.56 14.70 26.12 5.0% 6.76 12.91 22.26 10.0% 6.10 11.46 19.27 15.0% 5.55 10.27 16.92 20.0% 5.08 9.28 15.03 25.0% 4.68 8.45 13.48 30.0% 4.33 7.74 12.20 35.0% 4.03 7.14 11.12 40.0% 3.76 6.62 10.20 45.0% 3.53 6.16 9.42 50.0% 3.32 5.76 8.74

Table 2.35: Oza Field – Reserves portion – NPV Net to Hardy at various Discount Rates

Key dates are shown in Table 2.36 below: Oza Reserves-- Key dates for period starting 1 Jan 2010

Oza Reserves -- P90

Oza Reserves -- P50

Oza Reserves -- P10

Oil production start year 2010 2010 2010 Oil production (before economic limit) end year 2020 2025 2025 Oil production (after economic limit) end year 2016 2017 2021

Table 2.36: Oza Field – Reserves Portion – Key Dates



3. ATALA

The Atala field, located in onshore Nigeria’s OML 46 concession, was discovered in 1982 . The Atala field now forms part of a 34 km2 farm-out area, which were awarded to Bayelsa Oil Company Ltd and its joint venture partner Hardy Oil Nigeria. The Atala-1 discovery well encountered a number of oil and gas reservoirs and was logged but not tested. The reservoirs are contained between a number of near-parallel faults. The fault block has a dipping component for the trapping of hydrocarbons. The Field Development Plan for Atala4 mentions the development of five of the encountered reservoirs: U1, U2, U3, U4 and U7. This report will evaluate economically the contingent resources of these reservoirs only.

3.1 Geology and Geophysics

3.1.1 Database Hardy Oil has provided RPS Energy with the following geological and geophyiscal data: • Atala FDP from the Bayelsa Oil Company Limited4.• A GeoGraphix® project containing a 3D seismic survey and interpretation. • A Petrel™ project with the 3D seismic survey, including top grids, deviation and

checkshot surveys. It is noted that the deviation survey in the Petrel project is different from the deviation survey in the data package or the inferred deviations from the FDP-report4.

3.1.2 Seismic Interpretation The GeoGraphix® project contains interpretation of the U1, U2, U4 and U7 horizons. RPS agreed with the interpretation of U1 and U4 reservoirs, apart from a small upturn of the U1 horizon against the northern fault, which is not seen on seismic. The U1 horizon was re-interpreted to be representative of the seismic up against the northern NW-SE fault. The U2 horizon is located in a zone of seismic reflector discontinuity, leading to a difficult interpretation. The U2 horizon was interpreted as inlines only, causing inconsistencies with the interpretation of the 3D cube. This necessitates a re-interpretation by RPS. A full interpretation has been carried out for the U3 horizon, due to none being provided. RPS disagreed with the interpretation of U7 particularly in the west of the structure U7 has therefore been reinterpreted to conform to the seismic data.

4 Field Development Plan for Atala Field by Eogas, March 2008



3.1.3 Depth Conversion Depth conversion was carried out using the checkshot survey for Atala-1. It has been noted that two different checkshot surveys exist: one from the Petrel project and the other from the Eogas FDP. The Bayelsa checkshot table in the FDP4 was used for time-depth conversion. A simple polynomial z = 0.0005*TWT2 + 2.9643*TWT - 19.266 was drawn up in excel. The resulting depth surface from the TWT did not match well tops provided in the Eogas FDP and a bulk shift was applied to correct for depth discrepancies. This was done with the objective to use the same contacts, mentioned in the Eogas FDP. The base reservoir tops were created by bulk shifting the surface to the well base provided in the report and therefore assuming a consistent reservoir thickness.

3.1.4 Detailed Discussion of Structure Maps

3.1.4.1 U1 Reservoir Minor reinterpretation in the north of the structure was carried out to conform to the seismic data: The original seismic interpretation shows the horizon pick steepening up against the fault by not acknowledging the seismic data which creates additional volumes. U1 is a four-way dip closure bounded to the north and south by two NW-SE trending faults. The OWC at 6985 ft TVDSS rests against the southern fault and the GOC at 6930 ft TVDSS forms a four-way closure (Figure 3.1). Note that no GOC was seen in Atala-1 and that the mid case GOC is based on the mid-point between the crest of the structure and the OUT in Atala-1 (see page 24 of ref. 4). Also note that the re-interpreted crest of the structure is lower than the one mentioned and that this will negatively affect the GOC and STOIIP. In view of the large uncertainties, already present, the GOC in the FDP has been maintained.



GOC

OWC

GOC

OWC

Figure 3.1: U1 Structure Depth Map

3.1.4.2 U2 Reservoir A full reinterpretation for U2 was carried out by RPS Energy and the resulting top structure map is included as Figure 3.2.

The U2 horizon shows a three-way dip closure resting on the northern NW-SE trending fault. The GOC is estimated at 8147 ft TVDSS and an OWC at 8219 ft TVDSS. ). Note that no GOC was seen in Atala-1 and that the mid case GOC is based on the mid-point between the crest of the structure and the OUT in Atala-1. Note that the re-interpreted crest of the structure is lower than the one mentioned and that this will negatively affect the GOC and STOIIP. In view of the large uncertainties, already present, the GOC in the FDP has been maintained.



GOC

OWC

GOC

OWC


3.1.4.3 U3 Reservoir A full interpretation was carried out for U3 as no interpretation was provided. The resulting top structure map is shown in Figure 3.3.

The U3 accumulation shows a four-way dip closure at the 8400 ft TVDSS GOC contact and a gas trap against the northern fault. The OWC at 8416 ft TVDSS surrounds the main gas pool and spills out against the northern fault.

3.1.4.4 U4 Reservoir No reinterpretation of U4 was carried out and the Eogas interpretation was considered reliable. U4 is a three-way dip closure against the northern NW-SE fault and contains two structural highs (Figure 3.4). The GOC is taken at 8693 ft TVDSS from petrophysical evidence and the OWC at 8762 ft TVDSS.



GOC

OWC

GOC

OWC


GOC

OWC

GOC

OWC


3.1.4.5 U7 Reservoir A full reinterpretation of U7 was carried out leading to a different structure map (see Figure 3.5).



The U7 accumulation shows a pool against the northern fault with some minor intersecting faults. Closure in the south-east is uncertain due to the limit of the 3D survey. A GOC at 10745 ft TVDSS and a OWC at 10753 ft TVDSS have been assumed from petrophysical evidence in Atala-1.

GOC

OWC

GOC

OWC


3.2 Petrophysics The petrophysical log evaluation of Atala-1 was independently verified. The Atala-1 well had a full suite of modern logs and therefore the petrophysical uncertainty is expected to be lower than the old Oza wells. However, pertinent log data below U5.5 was not supplied for this work. and could therefore not been verified. The Eogas assessment5 mentions net pay sands of 180, 77 and 152 ft for the U6.0, U6.5 and U7.0 respectively. A Vshale cut off value of 30% is mentioned for Atala-15. This seems inappropriate, since most reservoirs would turn out to be non-pay. It is suspected that a much higher or no Vshale cut-off was used to determine average properties. The porosity was determined from a density-neutron approach, but due to an unusable neutron curve, the porosity result could not be independently verified. In the light of regional evidence, the porosity result seems reasonable.

5 Petrophysical Evaluation of the Atala-1 well. Ankorpointe report, 2008.



The saturation calculations were based on m=n=2. Pickett plot evidence and regional evidence suggest a lower m and n (1.8). This could lower water saturations. The reported water saturations appear reasonable however. The petrophysical analysis in ref. 5 mentions a GDT in the U7 of Atala-1, whilst an OWC is implied in the Eogas FDP4. RPS Energy confirms that there is indeed a likelihood of oil in the base of the U7 of Atala-1 and therefore supports the analysis in the FDP. It is noted that the tops and contacts, reported in Table 2 of ref. 5 are different from the ones, mentioned in ref. 4 (Table 3). It is assumed that the data in ref. 4 are correct, since they were used for further development planning work. Note however that the FDP tops also differ with the Petrel project, but this has been rectified by depth shifting to the tops, mentioned in ref. 4 (see section 3.1.3).

3.3 Volumetric Estimates RPS has used Eogas’ input parameters for calculating volumes deterministically. Although valuation will been done on a range of reserves it was decided to use a relatively wide range on recovery factor only, whilst using a single volumetric estimate. With contacts, obtained from ref. 4, separate estimates for GIIP and STOIIP were made.

3.3.1 U1 Reservoir Input parameters for volumetric estimates are summarised in Table 3.1.

The total GRV is 9.6 km3 split up over a gas cap (0.27 km3) and oil rim (9.33 km3).

Contact N/G Porosity Sw FVF

Unit ft TVDSS % % % scf/cf or rb/stb

Gas 6930 15 208.7

Oil 6985 62 28.5

33 1.36

Table 3.1: U1 Input for Volumetric Estimates

The deterministic volumetric estimates of GIIP and STOIIP are summarised in Table 3.2.

GIIP

(bcf)

STOIIP

(MMstb) U1

0.3 5.1

Table 3.2: U1 Volumetric Estimates (mid case)



For comparison, Eogas has calculated a GIIP of 4.3 Bscf and a STOIIP of 8.4 MMbbls for the U1 reservoir.


The total GRV is 20.2 km3 split up over a gas cap (1.96 km3) and the oil rim (18.24 km3).



Gas 8147 15 229.7

Oil 8219 53 25.5

30 1.53


The deterministic estimates of GIIP and STOIIP are summarised in Table 3.4.

GIIP

(bcf)

STOIIP

(MMstb) U2

1.8 6.8

Table 3.4: U2 Volumetric Estimates (mid case)










Gas 8400 24 15 228.2

Oil 8416 67

26 27.6 1.56


GIIP

(bcf)

STOIIP

(MMstb) U3

5.4 2.3

Table 3.6: U3 Volumetric Estimates





Gas 8693 15 227.2

Oil 8762 75 26.6

21.9 1.66



GIIP

(bcf)

STOIIP

(MMstb) U4

1.6 7.9




The total GRV is 118 km3 split up over a gas cap (112 km3) and the oil rim (6 km3).





Gas 10745 24.6 14.5 235.3

Oil 10753 62.5

20 27.5 2.05



GIIP

(bcf)

STOIIP

(MMstb) U7

123 1.6


For comparison, Eogas has calculated a GIIP of 117 Bscf and a STOIIP of 2 MMbbls for the U7 reservoir.

3.4 Reservoir Engineering

3.4.1 Methodology A full simulation model was built for the reservoirs, proposed for development in Atala. For valuation purposes, development scenario A2 was selected, which avoids re-using the 25 year old Atala-1 well. The A2 scenario consists of the following ingredients: 1. Drilling of two new deviated wells: Atala-C and Atala-D 2. Start oil production as of 1Q12 from the U1 and U4 reservoirs from both wells 3. Re-injecting produced gas for 12 years in a dedicated gas-disposal well 4. Switching to U1 and U2 reservoirs after 6 years of production 5. Recomplete both wells after 12 years to the U3 and U7 reservoirs for commercial

gas production together with their oil resources. Atala-1 was not production tested, but ref. 4 mentions a number of reasonable assumptions for initial rate and fluid properties to be used. Other forecast assumptions for the A2 scenario as listed in ref. 4, were considered reasonable if not a bit too harsh (cut-off at BSW of 65%). The simulation work from ref. 4 indicated an average recovery factors for the developed reservoirs of 23.9%, which is considered reasonable for this type of drive



mechanism. No STOIIP variation was supplied in ref. 4 and it was decided therefore to vary only the recovery factor to obtain a range in resource estimates. Note that the range in resource estimates in Table 10 of ref. 4 was considered too narrow. For the low and high cases, recovery factors of 15% and 35% have been assumed and the forecasts have been adjusted accordingly by assuming a faster and slower decline from the initial rate.

3.4.2 Oil Resources For valuation purposes, the Atala oil forecasts were adjusted by the following rationale: • Start production as per 1 Jan 2012. • Keep initial well rates and the duration of the forecasts the same as in the FDP. • Adjust mid case resources for the reservoirs to be developed by adjusting with

the new/old STOIIP ratio. This implicitly means keeping the recovery factor the same as obtained from the simulation

• Decline the forecast faster or slower, taking into account the new resource estimates.

• For the 1C and 2C estimates, multiply the new STOIIP’s with RF = 15% and 35% and decline from the initial rates to achieve these resources at the end of the forecast.

In this way the following resource distribution was obtained (see Table 3.11) for the Contigent Resources, planned for Development:

Reservoir 1C 2C 3C

U1 0.77 1.26 1.79U2 1.02 1.64 2.37U3 0.35 0.59 0.81U4 1.62 2.48 3.78U7 0.25 0.35 0.57

Total 4.01 6.32 9.32Note: Technical values, cut off at 10 bopd per well

Atala - Estimated Oil Resources

Resources (MMbbl)

Table 3.11: Atala Contingent Resources (Oil) ‘Development Pending’

The corresponding oil forecasts are shown in Figure 3.6. Note the timings of zone changes.



3.4.3 Gas Resources For the reservoirs under development, gas production only starts as of year 12 (or 2023) from the U3 and U7 reservoirs. Before that time the associated gas is assumed to be reinjected. The results for the gas recoveries, as mentioned in the FDP4, were not considered reliable: • The U3 reservoir had a total GIIP in the FDP of 22.32 Bscf (19.58 Bscf in the gas

cap and 2.74 Bscf as associated gas). A reported gas recovery of 20.77 Bscf or 93% seems excessive.

• The U7 reservoir holds a gas cap GIIP of 117 Bscf in the FDP which is more or less confirmed by RPS, but the FDP only recovers 22.2 Bscf or 18%. This seems excessively low even for one well.

RPS has reviewed the gas resources for Atala by applying the following recovery factor range on the GIIP’s, determined by RPS (see Table 3.12):

Atala Forecast of Contingent Resources 'Pending Development'

0

1000

2000

3000

4000

5000

6000

2012 2014 2016 2018 2020 2022 2024 2026 2028 2030 2032

Ave

rage

year

lyO

ilPr

oduc

tion

(bop

d)

3C forecast2C forecast1C forecast

U1+U4 U1+U2 U3+U7

Figure 3.6: Atala Production Forecasts for Oil



U3 U7 Total

Gascap 5.37 123 128.37Associated 2.19 negligible 2.185

Total 7.555 123 130.5551C 60% 40%2C 80% 50%3C 80% 60%1C 4.53 49.20 53.732C 6.04 61.50 67.543C 6.04 73.80 79.84

GIIP (Bscf)

Recovery Factor

Contingent Resources

(Bscf)

Atala - Estimated Gas Resouces

Reservoir

Table 3.12: Atala Contingent Resources (Gas) ‘Development Pending’

Gas production forecasts were generated starting mid 2023, reducing the initial gas production for U3, but increasing the plateau rate for U7 to 15 MMscf/d to accommodate the increased resources. Due to the increased resources, the duration of the 2C and 3C forecasts was extended as well. The corresponding forecasts are shown in Figure 3.7.

Atala Gas Forecast of Contingent Resources 'Development Pending'U3 and U7 reservoirs only

0

5

10

15

20

25

2020 2025 2030 2035 2040 2045 2050

Ave

rage

Gas

Prod

uctio

nR

ate

(MM

scf/d

)

2C forecast3C forecast1C forecast

Figure 3.7: Atala Production Forecasts for Gas

3.4.4 Other Resources Additional contingent resources in Atala were found in the U5.0, U5.5, U6.0 and U6.5 reservoirs. No development plan exists for these reservoirs, so they are contained in a lower class of contingent resources: ‘Development on Hold’. Table 8 in ref. 4 mentions notional GIIP’s and STOIIP’s, calculated by Eogas for these Resources.



No seismic interpretation is available for these reservoirs, but RPS-Energy did carry out an interpretation of the largest of these reservoirs, U6.0 (see Figure 3.8) . Based on a GDT of 11163 ft TVDSS in Atala-1, a GIIP of 191 Bscf was calculated, which is 21% lower than the 240 Bscf GIIP, quoted for U6.0 in ref. 4. Using the same recovery factor of 78.5%, RPS-Energy arrives at a resource volume of 150 Bscf for the U6.0 reservoir. It should be realised that the 191 Bscf represents a 1C figure rather than a 2C, due to the conservative assumptions of a GDT and minumum 31.7 m pay in Atala-1. The other reservoirs (U5.0, U5.5 and U6.5) have much smaller GIIP’s and were no further verified by RPS Energy. It should be noted that no clear barrier exists between the U6.5 and U7.0 reservoirs and is believed that the 27 Bscf Resources in the U6.5 can probably be drained with U7.0 development wells.

Figure 3.8: Atala U6 reinterpreted top structure map



APPENDIX 1: GLOSSARY OF TERMS AND ABBREVIATIONS

API American Petroleum Institute asl above sea level B Billion bbl(s) Barrels bbls/d barrels per day Bcm billion cubic metres Bg gas formation volume factor Bgi gas formation volume factor (initial) Bo oil formation volume factor Boi oil formation volume factor (initial) Bw water volume factor bopd barrels of oil per day BTU British Thermal Unit Bscf billions of standard cubic feet bwpd barrels of water per day CO2 Carbon dioxide condensate liquid hydrocarbons which are sometimes produced with

natural gas and liquids derived from natural gas cP centipoise CROCK rock compressibility Cw water compressibility DBA decibels Ea areal sweep efficiency EMV Expected Monetary Value EPSA Exploration and Production Sharing Agreement ESD emergency shut down Evert vertical sweep efficiency FBHP flowing bottom hole pressure FTHP flowing tubing head pressure ft feet ftSS depth in feet below sea level GDT Gas Down To



GIP Gas in Place GIIP Gas Initially in Place GOR gas/oil ratio GRV gross rock volume GWC gas water contact H2S Hydrogen sulphide HIC hydrogen induced cracking IRR internal rate of return KB Kelly Bushing ka absolute permeability kh horizontal permeability km kilometres km2 square kilometres kPa kilopascals kr relative permeability krg relative permeability of gas krgcl relative permeability of gas @ connate liquid saturation krog relative permeability of oil-gas kroso relative permeability at residual oil saturation kroswi relative permeability to oil @ connate water saturation kv vertical permeability LNG Liquefied Natural Gases LPG Liquefied Petroleum Gases M thousand MM million M$ thousand US dollars MM$ million US dollars MD measured depth mD permeability in millidarcies m3 cubic metres m3/d cubic metres per day MMscf/d millions of standard cubic feet per day m/s metres per second msec milliseconds mV millivolts Mt thousands of tonnes MMt millions of tonnes



MPa mega pascals NTG net to gross ratio NGL Natural Gas Liquids NPV Net Present Value OWC oil water contact Pb bubble point pressure Pc capillary pressure petroleum deposits of oil and/or gas phi porosity fraction pi initial reservoir pressure PI productivity index ppm parts per million psi pounds per square inch psia pounds per square inch absolute psig pounds per square inch gauge pwf flowing bottom hole pressure PVT pressure volume temperature rb barrel(s) of oil at reservoir conditions rcf reservoir cubic feet RFT repeat formation tester RKB relative to kelly bushing rm3 reservoir cubic metres SCADA supervisory control and data acquisition SCAL Special Core Analysis scf standard cubic feet measured at 14.7 pounds per square

inch and 60° F scf/d standard cubic feet per day scf/stb standard cubic feet per stock tank barrel SGS Sequential Gaussian Simulation SIS Sequential Indicator Simulation sm3 standard cubic metres So oil saturation Sor residual oil saturation Sorw residual oil saturation (waterflood) Swc connate water saturation Soi irreducible oil saturation SSCC sulphur stress corrosion cracking



stb stock tank barrels measured at 14.7 pounds per square inch and 60° F

stb/d stock tank barrels per day STOIIP stock tank oil initially in place Sw water saturation $ United States Dollars t tonnes THP tubing head pressure Tscf trillion standard cubic feet TVDSS true vertical depth (sub-sea) TVT true vertical thickness TWT two-way time US$ United States Dollar Vsh shale volume W/m/K watts/metre/° K WC water cut WUT Water Up To

φ porosity

µ viscosity

µgb viscosity of gas

µob viscosity of oil

µw viscosity of water



APPENDIX 2: SEISMIC TIES

Horizon Well Hardy Depth Map (ft)

Well Picks ( ft TVDSS) Difference Observation

Oza-1 5812 5808.5 3.5

Oza-2 6019 6016.0 3

Oza-3 5844 5855.98 -11.98 K7.2

Oza-4 5923 5882.3 40.7 111ft difference between K7.0 and K7.2 (82ft isopach). Near fault.

Oza-1 6158 6152.7 5.3

Oza-2 6375 6366 9

Oza-3 6189 6191.3 -2.3 L2.2

Oza-4 6211 6180.3 30.7 Near fault

Oza-1 6224 6219.2 4.8

Oza-2 6450 6435.13 14.87

Oza-3 6271 6272.5 -1.5 L2.4

Oza-4 6281 6255 26 Near fault

Oza-1 6330.5 6326.20 4.3

Oza-2 6542 6537.11 4.89

Oza-3 6350 6363.4 -13.4 L2.6

Oza-4 6352 6343.9 8.1

Oza-1 7268 7269.3 -1.3

Oza-2 7360 7444.62 -84.62 Fault

Oza-3 7252 7246.3 5.7 L7.0

Oza-4 7246 7249.0 -3

Oza-1 9364 9366.0 -2

Oza-2 9329 9328.05 0.95

Oza-3 N/A N/A N/A M5.0

Oza-4 9286 9277.7 8.3

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