TAQA Bratani Ltd. TAQA BRATANI LTD. P1995 RELINQUISHMENT DOCUMENT

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1 TAQA BRATANI LTD. P1995 RELINQUISHMENT DOCUMENT

2 Contents 1.0 Licence Information Licence Synopsis... 3 Firm Commitment... 3 Contingent Commitment... 3 Commitment Status Work Programme Summary... 5 Firm Commitments... 6 Contingent Commitment Database... 7 Wells Database... 7 Seismic Database Prospectivity Update... 9 Middle Jurassic Tulla Prospect... 9 Middle Jurassic Torridon Discovery Upper Jurassic Thunder Prospect (previously Tyrone 2) Upper Jurassic Tinsel Lead (previously Tyrone 1) Upper Jurassic Tennant Complex Lead Further Technical Work Undertaken Reservoir Quality Analysis Geochemistry Rock Physics and Lithology Classification Fault Seal Study Risking and Volumetrics Resource and Risk Summary Conclusions Clearance... 32

3 RELINQUISHMENT DOCUMENT (P1995) 1.0 Licence Information Licence Number: P1995 Licence Round: 27 th Licence Round Initial Term: 1 st January 2013 (4 years) Licence Type: Traditional Block Numbers: 210/25b, 211/21b, 211/26b Operator: TAQA Bratani Limited (50 %) Partners: Nautical Petroleum Limited (50 %) 2.0 Licence Synopsis Licence P1995 was initially awarded to TAQA Bratani Ltd (50 %) and Agora Oil and Gas (UK) Ltd (50 %) in January 2013 as part of the 27 th Licence Round as a Traditional licence. Both Agora and Nautical are wholly owned subsidiaries of Cairn Energy PLC ( Cairn ). The original terms of the licence were as follows: Firm Commitment The Licensee shall: a) Obtain 200 km 2D seismic data. b) Obtain 100 km2 3D seismic data. c) Reprocess 200 km2 3D seismic data. d) Conduct rock physics and AVO studies. e) Drill a well on the Tulla Prospect to 2600 m or 100 m below Top Brent, whichever is the shallower. Contingent Commitment The Licensee shall drill a well on Tyrone to 4000m or 50 m below Top Heather, whichever is the shallower dependent on the seismic interpretation determining whether significant erosion has taken place over the East Shetland Platform to source sufficient quantities of quartzose sediment confirming reservoir presence.

4 Commitment Status Firm commitments a-d have been fulfilled and commitment e has been transferred to other licences. Seismic interpretation was unable to confirm significant erosion of the East Shetland Platform to derisk reservoir presence at the Thunder prospect (previously Tyrone). Accordingly, the OGA approved the application for a waiver on the Contingent well commitment. Figure 1: Map showing original licence area outlined in red. The licence comprises three sub-blocks; 210/25b, 211/21b and 211/26b.

5 3.0 Work Programme Summary Original interpretations were carried out using the ESB09 3D seismic survey which covers the entirety of the P1995 licence area. During the licence term new seismic data was acquired, ESB11 and ESB14, the first of which is a good quality geostreamer volume, covering some of the licence area (Figure 4) and the second of which is a pre-stack depth migrated volume using the merged and reprocessed ESB11 and ESB09 seismic surveys which covers the whole of the licence area. Interpretation of this seismic allowed the following leads and prospects to be identified at Upper and Middle Jurassic levels. Tulla - Middle Jurassic Brent Group Torridon - Middle Jurassic Brent Group Tinsel (previously Tyrone North) - Upper Jurassic Tennant - Upper Jurassic Thunder (previously Tyrone South) - Upper Jurassic Figure 2: Map showing prospects and leads within P1995 licence area as identified from interpretation of 3D seismic volumes.

6 The original terms of the licence have been fulfilled as detailed below: Firm Commitments a) Obtain 200 km 2D seismic data 2D seismic lines were acquired across the East Shetland Platform, however these were inconclusive in determining the amount of erosion present on the East Shetland Platform. b) Obtain 100 km2 3D seismic data 100 km2 of CGG96 was acquired. c) Reprocess 200 km2 3D seismic data ESB09 and ESB11 surveys were merged and re-processed to create the ESB14 pre-stack depth-migrated seismic survey which covers the entire licence area. d) Conduct rock physics and AVO studies A number of instantaneous attributes were extensively employed in order to define pinch-out edges, truncations and to identify the on-lap/down-lap geometry. Rock physics analysis was performed for the key wells in the area in order to compute elastic properties and generate the relevant cross-plots for use in calibrating seismic inversion products. Mu-Rho volume was created to help identify sand packages. Lithology classification was attempted using the basinal wells 210/30b-3 and 210/30-1 to try and differentiate sand and shale. e) Drill a well on the Tulla prospect to 2600 m or 100 m below Top Brent, whichever is the shallower Well commitment transferred to other licences. Contingent Commitment a) The Licensee shall drill a well on Tyrone to 4000m or 50m below Top Heather, whichever is the shallower, subject to contingent criteria The OGA approved a waiver to the well commitment.

7 4.0 Database Wells Database Seven wells are currently located within the P1995 licence area: 210/25-4 Dry Hole 210/25b-8 Dry Hole 210/25b-8Z Dry Hole 210/25c-6 Junked Well 210/25c-6A Oil Shows 210/25c-7 Dry Hole 211/26-5A Dry Hole Figure 3: Map showing location of wells used for technical evaluation of the licence. Not all production wells are shown; however all were available for the TAQA operated fields.

8 All wells are Plugged and Abandoned. All exploration and appraisal, producer and injector wells from TAQA operated fields were available as well as all released well data available through CDA. Seismic Database A number of different seismic volumes were available; however, the main ones that were used for the interpretation of licence area were the ESB09 (courtesy of PGS and TGS), ESB11 and the ESB14 seismic volumes (courtesy of PGS) as these were the most modern and best quality data sets that covered the licence area. Figure 4: Map showing coverage of seismic surveys. The main surveys used during the interpretation were the ESB09 (pink), ESB11 (blue) and ESB14 (red) surveys.

9 5.0 Prospectivity Update Middle Jurassic Tulla Prospect The Tulla prospect is a conventional faulted dip closure at Middle Jurassic Brent Group level with fault closure to the north-west (Figure 5). It is located approximately 8 km southwest of the Tern Platform. The north-western bounding Pobie Fault defines the western limit of the Tern-Eider Ridge. A period of post Jurassic structural compression has effectively inverted the southern end of the Tern Horst and has contributed to the dip closure that defines the Tulla prospect. The inversion has induced local reverse movements on a fault to the east of the Tulla structure but well beyond the spill point. Figure 5: Top Brent depth map showing location of Tulla prospect (outlined in red) relative to Tern and Hudson Fields.

10 For the 27 th licensing round Tulla was interpreted on the ESB09 (PGS streamer speculative survey) which covers all three blocks making up the licence area. In addition to the conventional reflectivity volumes, various structural attribute volumes were also calculated in 2010 (Baker RDS Similarity, SimDip, Coloured Inversion and Curvatures) and these were used extensively to aid fault interpretation at Top Brent level. Following the award of the P1995 licence, TAQA acquired the PGS ESB11 broadband geostreamer seismic survey, which allowed a re-interpretation of the Tulla prospect. In 2014 TAQA received the final pre-stack depth merged (PSDM) volume; part of a large-scale project covering all of TAQAs Northern North Sea assets. This volume merged the re-processed EOK12 (PGS geostreamer data), ESB11 and ESB09 seismic surveys to create the ESB14 survey which covered the whole of the licence area (Figure 4). The Tulla prospect was re-interpreted using this new volume. Although there was some slight lateral movement on the faults, there was no major nor unexpected changes with the main faults appearing to be similar in pattern to what had been previously interpreted (Figure 6). Figure 6: Map showing difference in fault polygons as interpreted on the PSTM ESB11 seismic survey (blue) and the PSDM ESB14 seismic survey (red). It shows a slight lateral movement of the faults, however, the main faults appear to be similar in pattern.

11 There were slightly fewer mappable faults over the Tulla prospect, however where present the faults tended to be clearer and more continuous (Figure 7). The key faults for the Tulla trapping mechanism are no longer considered robust and therefore a significant risk to containment has been added. Figure 7: Base Mid Ness Shale Variance Attribute showing a comparison between the PSTM ESB11 survey (right) and the newer PSDM ESB14 survey (left). The PSDM ESB14 survey appears to be smoother and less noisy than the previous dataset with fewer mappable faults present. Seismic data courtesy of PGS. Using the updated interpretation from the depth migrated seismic; the new surfaces from Top Brent (previously unable to be picked on the old seismic) and Base Mid Ness Shale (Figure 8) were incorporated into an updated model, which included property modelling methodology more in line with the methodology used on TAQAs other Brent fields. As the faulting had not significantly changed, the previous faults were retained, with the offsets updated based on the new surface interpretation. The incorporation of these new input surfaces into the model improved connectivity of the Upper Brent across the prospect, however did not improve the offset along the main bounding fault, with Brent-Brent cross fault juxtaposition occurring at 8,300 ft (Figure 9). For fill-to-spill scenarios to 8,400 ft, the Pobie fault would have to seal in order to prevent migration across the fault and up-dip.

12 Figure 8: Seismic line showing interpretation across the Tulla prospect on the ESB14 PSDM seismic survey and the well ties to the offset TA22S1 and 210/25c-7 wells. On previous volumes the Top Brent surface was unable to be interpreted. Both Top Brent and Base Mid-Ness Shale were used as input horizons for the updated model build. Seismic data courtesy of PGS.

13 Figure 9: Comparison of previous structural model with the updated structural model based on the seismic interpretation from the PreSDM ESB14 survey. Whilst offset along the main bounding fault has not increased, the addition of a Top Brent input surface has allowed improved connectivity throughout the Upper Brent across the prospect. Even with the additional volume added by assuming fault seal along the Pobie Fault, the volumes were still relatively small and other scenarios were considered that may increase the STOIIP within the prospect. The nearby Hudson Field is seen to have different contacts within the Upper (7,188 ft tvdss) and Lower Brent (6,704 ft tvdss) due to the sealing nature of the Mid-Ness Shale. If the Mid- Ness Shale and the Pobie Fault were found to be sealing at Tulla, then both the Upper and Lower Brent could be filled to spill, 8,400 ft tvdss and 8,540 ft tvdss respectively. The main uncertainties with the Tulla prospect, therefore, are the ability of the Pobie fault to seal and the possibility of the Mid-Ness Shale acting as a seal to allow separate contacts in the Upper and Lower Brent. The largest volume cases require the Pobie Fault to seal where there is Brent-Brent cross fault juxtaposition. The Pobie fault is known to seal at Tern where the Brent reservoir is offset against the Upper Jurassic Humber Group (non-reservoir shales). Data across TAQA Brent fields shows limited evidence for fault seal where there is Brent-Brent juxtaposition and in general it is found that faults that have reservoir juxtaposition are non-sealing. There are some TAQA Brent fields

14 that do show examples of Brent-Brent fault seal; North Cormorant Block IV and Kerloch. However, Block IV is a large slump block and therefore additional movement on the faults as a result of this slumping may have led to their sealing nature and Kerloch is significantly deeper than the Tulla prospect and reservoir quality and depth related diagenesis may have aided fault seal in this area. A small risk is associated with the reservoir quality at the Tulla location and this is due to the low netto-gross seen throughout the nearby 210/25c-7 well. This well also encountered a significantly thinner Upper Brent than other offset wells and a thicker Mid-Ness Shale. The erosion/non-deposition of the Upper Ness sands and the low net-to-gross are considered to be local effects and as a result the well has been excluded from the petrophysical modelling averages. If rock properties at Tulla were found to be similar to the 210/25c-7 well, then it would be considered a failure case and therefore the risks associated with the reservoir quality have been included in the overall risking and not the volumetrics. Different combinations of these key risk uncertainties (fault seal and Mid-Ness Shale seal) allowed four different scenarios to be calculated (Figure 11 - Figure 14) and these combinations with the assigned risks (Figure 10) are detailed below: Figure 10: Summary table of key risks associated with each scenario for the Tulla prospect.

15 Figure 11: Summary of Case M scenario for Tulla prospect. Figure 12: Summary of Case N scenario for Tulla prospect.

16 Figure 13: Summary of Case O scenario for Tulla prospect. Figure 14: Summary of Case P scenario for Tulla prospect.

17 Despite there being a potentially large upside associated with case P, a chance of success of only 6 % (Figure 16), due to it requiring both the Pobie Fault and Mid Ness Shale to act as seals, means that given the current economic climate, the Tulla prospect is uneconomic and cannot be taken any further. Cases M, N, O and P all belong to a technical success scenario in which hydrocarbons are discovered. For the Tulla prospect this has been given a chance of technical success of 73 % (Source: 100 %, Timing/Migration: 90 %, Reservoir Quality: 90 %, Closure 90 % and Containment: 100 %). Taking the 73 % chance of finding hydrocarbons and multiplying this by the probabilities of each of the cases (M-P) occurring (Figure 10), a total chance of success has been calculated and this is given in the table below (Figure 15). Summary of Tulla Volumes: STOIIP (MMstb) Low Mid High Chance of Success Case M % Case N % Case O % Case P % Figure 15: Table showing STOIIP associated with each of the cases as well as the chance of success.

18 Middle Jurassic Torridon Discovery The Torridon prospect (Figure 16) was discovered in 1987 by BP with the 210/25c-6A well. A full Brent sequence with oil shows was encountered, however at the time reservoir quality was not deemed sufficient to develop. Figure 16: Top Brent depth map showing structure across Torridon discovery with location of the discovery well 210/25c-6A on the flank of the structure. The structure is a rotational slump feature against the footwall of the east bounding fault of the Tern- Eider ridge (Figure 17 and Figure 18). The discovery well (210/25c-6A) was drilled on the flank of this structure and the up-dip potential was the main focus of the licence application.

19 Figure 17: Seismic line (shown in yellow in Figure 16) across the Torridon discovery showing current interpretation of BCU (green) and Top Brent (blue) horizons.seismic data courtesy of PGS. Brent Gp Tern Field Depth Ft tvd Torridon BCU Heather & Kimmeridge shales Figure 18: Cross-section across Torridon showing location of discovery well 210/25c-6A.

20 The crest of the structure lies at 11,200 ft tvdss and therefore the key risk with the prospect was the reservoir quality as the Brent group reservoir is seen to undergo significant degradation with depth. The application considered the possibility that early oil migration into the structure may have inhibited illitisation and preserved reservoir quality up-dip of the discovery well, however, recent work from the Pelican and North-West Hutton field areas has seen that degradation of reservoir quality with depth is primarily related to grain size and therefore facies. In both of these fields we see that coarse grained sands undergo significantly less degradation than fine grained sands and only coarse grained sands are able to retain reasonable reservoir quality at depth. Deterministic volumes for the Torridon discovery were calculated using the 210/25c-6A well properties as a base case and the average reservoir parameters from the Pelican Field as a high case. The STOIIP range is MMstb. Using the Pelican Field as an analogue, recovery factors on the whole are about 20 % which would give a reserves range of only MMstb. Given that the average reservoir properties for the Pelican field are better than those observed in the discovery well; it is unlikely that recovery factors of this level would be achievable. The location is too far from existing platforms to be drilled from there and would require development by subsea wells. The prospect is therefore considered uneconomic, at this time, to progress. Upper Jurassic Thunder Prospect (previously Tyrone 2) The Thunder prospect is an Upper Jurassic basin floor fan stratigraphic trap. It potentially consists of five individual lobes, encased within the mature Kimmeridge Clay Formation. The key risk associated with the prospect is the presence of sand in the basin. The presence of sand in the Cladhan Field at the relay ramp to the west of the Thunder basin and some thin sands with oil shows in the wells on the distal margin of the Thunder basin play (210/30-1, 210/30b-3 and 210/25c-6A) show that sands were being deposited during the Upper Jurassic. Although sands were clearly being deposited throughout the Upper Jurassic, what remains uncertain is the quantity and quality of these sands, if any, in the Thunder basin. Mapping of key reflectors within the basin is tricky, with the data suffering from seabed-multiple interference, especially at the Upper Jurassic level. The Base Cretaceous Unconformity and Top Brent events were able to be picked with some confidence across the area, however, the Heather, J66 and J62 flooding surfaces were much less confident picks (Figure 19). Whilst an attempt has been made to map the Thunder lobes within the basin, the confidence associated with these is low due to poor reflectivity within the Upper Jurassic section. An attempt was made to try and model the seismic response expected if sands were present by synthetically inserting 500 ft of sand from the analogous Miller Field into the 210/30b-3 well at the J56 surface in the Thunder basin (Figure 20). The modelling suggested that if similar reservoir sands were to exist within the Thunder basin that they may not be easily observed within the Kimmeridge Clay. This coupled with the conceptual model for the sands suggesting thin, laterally extensive sands that would fall below seismic resolution means it is unlikely that if sands were present in the basin that they would be easily visible, or indeed mappable. Despite evidence of erosion of Upper Jurassic sediment on the East Shetland Platform edge, it is difficult to quantify exact amounts; however, a figure of around 3 million cubic metres has been estimated (Figure 21). This in itself is not sufficient to meet GRV requirements for a Thunder success case and additional sediment would have to have been sourced from further afield or from erosion that cannot be interpreted from the existing data.

21 Seismic interpretation has been unable to confirm sufficient sediment source was available for the Thunder prospect. It is therefore considered too high risk to take any further. Attempts were made to try and de-risk this through the use of the available seismic (more detail can be found on this in section 6); however, whilst some of the work showed promise, none of these attempts were successful enough to increase the chance of success of the prospect, which remains at only 5 %. Figure 19: Maps showing interpretation of main Upper Jurassic seismic reflectors as interpreted for the evaluation of the Thunder prospect. Polygons showing the five Thunder lobes are shown on each map.

22 Figure 20: Synthetic modelling to show what seismic response sands may give if they were present in the Thunder basin. Work carried out using 500 ft sand from the Miller Field, inserted into the basinal well 210/30b-3.

23 Figure 21: Seismic line from East Shetland Platform to Thunder basin. Line shows erosion along edge of East Shetland Platform (white triangle). Wells on the platform go from the Tertiary interval directly into the Brent Group, meaning a significant section of Cretaceous and Upper Jurassic sediment is missing from the platform. Seismic data courtesy of PGS.

24 Upper Jurassic Tinsel Lead (previously Tyrone 1) The Tinsel lead is an Upper Jurassic base of slope wedge (Figure 22), deposited very early in the Upper Jurassic at the base of the hanging wall of the Tern-Eider Ridge fault blocks (Figure 23 and Figure 24). Figure 22: Map showing Base Cretaceous structural interpretation across Upper Jurassic Tinsel lead with offset wells. Seismic section line used in Figure 23 is shown in black.

25 Figure 23: Seismic line through Upper Jurassic Tinsel lead. Upper line shows interpretation carried out for initial application on ESB09 PSTM seismic data (courtesy of PGS and TGS), lower line shows interpretation carried out on ESB14 PSDM seismic data (courtesy of PGS). Seismic line location is shown in black on Figure 22.

26 Figure 24: Cross-section through Tinsel lead. Key risks for this lead are the stratigraphic trapping mechanism and the reservoir quality. The up-dip part of the lead relies on sealing against the Tern Horst where it is likely to be offset against the basement. Lateral and top seal are expected to be provided by the Kimmeridge Clay which the sands are deposited within. The other key risk is the nature of the sandstone input into hanging wall of the East Tern fault. The lead can be seismically mapped as a discrete wedge-shaped body immediately down-dip of known erosion of the Upper Brent in the Tern Field. Well based evidence from the Tern Field and adjacent fields suggests that neither the Pobie Fault nor the Tern East fault were active at the time of Brent deposition, meaning that the Brent did not depositionally thin onto the East Tern bounding fault. The Tinsel lead is located immediately down-dip of a complex slump zone at the eastern edge of the Tern Horst. Slumping and erosion at this eastern crest is thought to have contributed the sand into the Tinsel lead feature. This erosion is supported by the three wells closest to proposed slump zone TA25S3, TA25S1 and TA27S1, with the Upper Brent section missing in the latter two wells (Figure 25). TERN FIELD KESTREL FIELD Upper Ness Upper Ness Eroded Figure 25: Tern-Kestrel Brent Group correlation showing erosion of Upper Ness in nearest offset wells TA25S3, TA25S1 and TA27S1.

27 The lead lies in the depth range of 11,000 12,850 ft tvdss and therefore reservoir quality at these depths is uncertain. Diagenesis and compaction have the potential to severely reduce reservoir quality. Previous work suggested that the ability to charge the sandstones relatively early on may inhibit illite in the oil leg and preserve reservoir quality. Recent work carried out using core data from the Pelican and North-West Hutton fields suggests that early oil emplacement has little impact on the ability to preserve reservoir quality at depth, with facies predominantly grain size being the key control. The work carried out showed that coarse grained, clean sands such as fluvial channels underwent significantly less degradation than their finer grained, dirtier more marine facies such as shoreface sands, at the same depths. As the Tinsel lead is comprised of eroded/ slumped re-worked Upper Brent from the Tern Field, the depositional fabric of these re-worked Brent sands could have a significant impact on their ability to retain good reservoir quality at these depths. The Upper Ness, shown in Figure 25 is quite shaley and therefore any eroded Upper Brent may contain a significant proportion of fine grained, shaley material which could promote reservoir degradation at these depths. The risks associated with this lead are considered too high in the current economic climate for the lead to be progressed. Upper Jurassic Tennant Complex Lead The Tennant Complex lead is an Upper Jurassic channelised stratigraphic trap located to the northwest of the Tern-Eider Ridge. Amplitude extraction over the window of BCU and Top Brent horizons highlights the channelised deposits of the Home sands within the licence area (Figure 26). Figure 26: Maps showing location of Tennant channel complex as identified on a maximum amplitude extraction (left) and interpreted BCU structure (depth). The Home sands are a sequence of Upper Jurassic turbiditic sandstones which form in erosive channel features oriented perpendicular to the East Shetland Basin margin. The channels lie within the Kimmeridge Clay, which provides top and base seal to the sands (Figure 27).

28 Figure 27: Geological cross-section showing Tennant channel complex relative to Home Sands seen in 210/19-2. To investigate whether the fluid in the channels could be discriminated using seismic data, a fluid substitution was performed on well 210/19-2 over the Home sands interval. The seismic event at the top of the sand shows that a wet channel has a negative intercept with a positive gradient. An oil filled channel on the other hand would show a positive intercept with a positive gradient; a class III response. Geochemical evaluation of the 210/25b-8Z well suggests that the Kimmeridge Clay within the subbasin is immature and so localised charge from this nearby area is not possible. Any hydrocarbons would have to migrate distances of up to 20 km from a mature kitchen to the south-east of Otter, which is thought to be the source for both the Otter and Eider West Fields. Migration into the Tennant channels is therefore considered to be extremely high risk and for this reason the lead has not been taken any further.

29 6.0 Further Technical Work Undertaken Reservoir Quality Analysis Reservoir quality and the associated degradation with depth for the Middle Jurassic Torridon prospect were assessed using petrophysical data from the nearby wells as well as utilising in-house knowledge from a range of analogous Brent fields, in particular Pelican, Darwin and NW Hutton. Looking at the core from these fields in detail it was identified that facies (grain size, detrital clay content) had a significant control on the ability of a sand to preserve good reservoir quality at depth. Finer grained marine type sandstone facies (e.g. shoreface sands) show a higher potential for illite precipitation and tend to be located in stratigraphically deeper sections (in particular the Rannoch and Broom). Medium to coarse grained fluvial type sandstone facies (fluvial and tidal channels (Ness)) preserve the best reservoir quality due to their grain size and cleaner primary depositional character. The depositional fabric of the reservoir is therefore a key component in assessing the reservoir quality of deeper targets. Geochemistry Hydrocarbon fingerprinting studies have been performed within TAQA to enhance the understanding of the regional distribution of mature Kimmeridge Clay and the migration routes of the hydrocarbons to the producing fields. This study was particularly relevant to the Tennant lead where migration into the Upper Jurassic sands was considered a key risk. The geochemical study showed that oils from the Otter and Eider West Fields have significant similarities in composition, indicative of a shared mature kitchen to the south-east of Otter. If any hydrocarbons were able to migrate into the Tennant lead then it is most likely to have been sourced from this kitchen which is over 20 km away. Rock Physics and Lithology Classification Rock physics analysis was performed for the key wells in the area in order to compute elastic properties and generate relevant cross-plots for use in calibrating seismic inversion products. The resultant MuRho volume was found to be useful in identifying the sand packages within the Upper Jurassic when used in conjunction with the attributes (Figure 28) and reflection data. For many of the Upper Jurassic prospects and leads, in particular Thunder, the presence of reservoir sand presents the biggest risk. In order to try and de-risk this somewhat, a significant effort was made to try and use the available data to predict lithologies (sand or shale) within the Upper Jurassic interval. The two basinal wells (210/30b-3 and 210/30-1) were used for shale calibration and a Cladhan well (with a depth correction applied) for the sands. The 2D results derived from crossplotting P-Impedance vs. S-Impedance were encouraging; with test lines over the Thunder prospect showing that discrimination between sand and shale may be possible (Figure 30). Although these results were promising, they were ultimately unsuccessful in confirming sand presence in the basin and reducing the risk sufficiently.

30 TAQA Bratani Ltd. Figure 28: Seismic line showing cosine of phase attribute, used for helping to pick on lap, down lap and truncation events. Figure 29: Seismic line showing MuRho attribute across Thunder lobes. Attribute was found to be useful in identifying potential sand packages when used with reflectivity and other attribute volumes.

31 Figure 30: Line showing attempted lithological discrimination of Thunder prospect, highlighting potential sand presence in the Thunder-1 and Thunder-2 lobes. Fault Seal Study An independent fault seal evaluation was carried out by Tim Needham for the Tulla prospect which suggested that the main bounding fault (the Pobie Fault) could retain an oil column down to 8510 ft based on Shale Gouge Ratio (SGR) and Shale Smear Factor (SSF) methods. Whilst this study suggested that fault seal may work at the Tulla prospect location, analogue data from TAQAs Brent Fields gave limited evidence that fault seal would be present at the Tulla location and the risks associated with this were considered too high. Risking and Volumetrics Mapping of the licence area was carried out using the ESB14 Pre-Stack Depth Migrated Seismic Survey which covered the licence area. The updated mapping did not have a significant impact on the leads and prospects previously identified, due to limited fault movement at Brent level and issues with seabed multiples throughout the Upper Jurassic interval. Unfortunately, the subsequent risking and current economic climate deemed that the risks associated with the leads and prospects were too high to allow the prospects to be considered any further.

32 7.0 Resource and Risk Summary On the basis of the assessment of prospectivity on the Licence, recoverable reserves potential is considered to be low risk but small and uneconomic in the current climate or larger but extremely high risk. Partners agree to determine the P1995 licence one month from receipt of the licence determination document. Name Maturity Strat. Level Resource and Risk Summary STOIIP Key Risks/ Uncertainties Tulla Prospect Middle Jurassic MMstb Reservoir quality of the Brent Group Ability for fault seal along Pobie fault MNS seal Torridon Discovery Middle Jurassic MMstb Reservoir quality Depth conversion fault imaging Thunder Prospect Upper Jurassic MMstb Reservoir presence Reservoir quality Stratigraphic pinch-out Tinsel Lead Upper Jurassic MMstb Reservoir quality Reservoir Presence Trapping mechanism Tennant Lead Upper Jurassic MMstb Reservoir quality Trapping mechanism Migration 8.0 Conclusions Both Upper and Middle Jurassic sands are recognised as plays in this area, due to the Cladhan field to the west and the many surrounding Brent Group Fields. The prospects and leads identified within the licence area have been assessed and it is deemed that the risks associated with them are too high and reserves potential is considered to be small and uneconomic. The operator (TAQA) and its partner (Cairn) agree to determine the licence P1995 at the end of the Initial Term (31 st December 2016). 9.0 Clearance The operator, TAQA (50 %) and its partner Cairn (50 %) confirm that the OGA is free to publish information documented in this report and that all 3rd party ownership rights (on any contained data and/or interpretations) have been considered and appropriately cleared for publication purposes.