1. LICENCE INFORMATION. P209 Block 9/29a ALL. U.K. Block 9/29a (Part Block) Operator/Partners TAQA Bratani Ltd 81%, RWE DEA UK 19%

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1 1. LICENCE INFORMATION Licence P209 Block 9/29a ALL Licence Round 4th round Blocks U.K. Block 9/29a (Part Block) Licence Type Traditional (Production) Well Operator TAQA Bratani Ltd Operator/Partners TAQA Bratani Ltd 81%, RWE DEA UK 19% 2. LICENCE SYNOPSIS Licence P209, Block 9/29a (excluding Devenick) is a traditional production licence awarded to BP in the Fourth Round in TAQA acquired the acreage and operatorship from BP on 29th June RWE hold a 19% working interest in the licence. No obligations are outstanding on the acreage however, as part of the Fallow Process, DECC requested a timed plan for the area south of the Devenick Field (Figure 1) with a deadline of mid- December TAQA, on behalf of the partnership, requested additional time to fully evaluate the remaining potential of the licence and to provide a full assessment of the remaining prospectivity during the first half of DECC agreed to extend the deadline to deliver a rescue plan or relinquish the acreage by the end of This work was completed mid-2014 and it concluded that the partnership could not commit to the required drilling commitment to retain the licence. TAQA Bratani Ltd. confirms that DECC is free to publish this report and that all third party ownership rights (on any contained data and/or interpretations) have been considered and appropriately cleared for publication purposes.

2 Figure 1 Location Map for Licence P209 (Block 9/29a) with relevant well data, seismic survey and field locations posted (N.B. Harding and Gryphon development wells omitted for clarity) 3. WORK PROGRAMME SUMMARY The work programme to retain the licence was: To review our existing well and seismic database including seismic interpretation (based on 2004 Devenick 3D survey), well calibration, depth conversion and reservoir evaluation to provide a full assessment of the prospectivity of the acreage and to determine the presence of any drillable prospects On completion of the review it was concluded that there were no drillable prospects within the acreage due to the complete lack of mappable structural closures at any Tertiary interval. The only possible stratigraphic accumulation identified was in the Horda Formation, Frigg Sandstone that formed a series of complex sub-vertical injection features - these were considered to be too small and of very high risk to warrant testing.

3 No further analysis of the Upper Jurassic was undertaken by the partnership due to the high pressure, high temperature nature of any perceived prospectivity although BP had previously identified a feature at this level. 4. DATABASE The interpretation was undertaken on the Devenick 3D seismic survey acquired in 2004 (Figure 1). A total of six horizons were mapped and depth converted, Top Ekofisk, Top Maureen (only partially mappable), Top Heimdal, Top Sele, Top Balder and Top Horda. No structural closure could be identified on any of these surfaces within the P209 licence acreage outside the Devenick field area. A review of the closest offset well data, both on block and up dip to the west, reveals that at best only oil shows are present within the Tertiary section in the area (Figure 2 & Table 1). The nearest discovery is in the Norwegian sector where the 24/12-3 recorded a 9 foot oil column in a Heimdal reservoir. A total of three well penetrations have been made on block 9/29a: 9/29a-1 and 2, 2Z (S2). These wells are all located within the retained Devenick Field area. All three wells reached a total depth in the Late Jurassic, Brae Formation Sandstone. Figure 2 Regional Well Database including Tertiary Hydrocarbon Occurrences (Including Norwegian Sector)

4 Well Hydrocarbon Occurrence 24/9-3 Tested oil from Frigg Sands 24/9-9 (Bøyla Oil Field) Hermod (Flugga) Sands (Sele Formation) 24/ foot oil column in Hermod (Flugga) Sands 24/ foot oil column in Heimdal Sands 9/23b- 19 9/23a- 30Z 9/28-1a 21 foot gas column in Sele aged sands 51 foot gas column and 33 oil column in Sele aged sands Tested Water with minor oil (12 o API) and light gas from Danian Oil & gas shows also observed in Paleocene, Cretaceous, Jurassic & Triassic 9/28-3 Oil shows in Sele aged sands as well as Heimdal & Maureen 9/28b-5 9/28b-17 Oil shows in base of Maureen Minor shows in Heimdal Table 1 Regional Tertiary Hydrocarbon Inventory (Including Norwegian Sector) 5. PROSPECTIVITY UPDATE Block 9/29a is located south of the TAQA operated Devenick Field which produces from Late Jurassic, Brae Formation sandstones via a single well development and subsea manifold tied back to the East Brae Platform. The block evaluation identified four Frigg Sand injectite features in the licence with a P50 STOIIP range of MMstb. No direct hydrocarbon indicators (DHI) were identified on seismic and the leads require a stratigraphic trapping mechanism to be successful. All four leads are considered to be too small or carry too high a risk to be economically viable and relinquishment of the licence is recommended. Reservoir Block 9/29a is located within the depocentre of the prolific Paleocene and Eocene deep water fan deposits of the Maureen Formation and the Heimdal, Flugga and Frigg Sandstone Members. Offset well data and production experience from the TAQA operated Harding Field to the north west indicates these sands would prove to be excellent reservoirs should a hydrocarbon accumulation be encountered. However the prolific nature of their development almost precludes any chance of a stratigraphic trap particularly in the Early Paleocene. The more variably developed Eocene Frigg Sandstones may have some potential for a stratigraphic trap but carry significant risk. Source/Migration The Kimmeridge Clay Formation is the source rock for all the producing fields in the area and is considered to be mature in this region. The most probable migration path for hydrocarbons into the block would be from the Norwegian sector to the east. Source is not considered to be a risk, however migration into the Tertiary sections requires some vertical component e.g. pre-tertiary graben faults if being sourced from the east that cannot be identified from seismic data over the P209 licence. Trap The principal risk for Tertiary prospectivity in the block is considered to be the trapping mechanism. As previously stated the prolific development of the Paleocene and Eocene sands makes a stratigraphic containment virtually impossible. Additionally, numerous penetrations of water bearing Tertiary sands up dip and to the west in block 9/28a (Figure 2 & Table 1) suggests a stratigraphic

5 trap in this block is highly unlikely. Unfortunately the recent review did not identify any four-way dip closures within the Tertiary section. Seal A shale package consisting of the Sele, Balder (Tuff) and Horda Shale lies directly above the thick (>1500 feet) Heimdal and Maureen sand packages and can be correlated on a semi regional basis from wireline and biostratigaphy data (Figure 3). This shale package could provide a competent top seal for any structural closure identified at Heimdal level. However risk must be assigned to the presence of Frigg Sands that are variably developed within the Horda Formation. Seismic data suggests that these were emplaced or remobilised by injection processes and may constitute a significant breech risk for the Heimdal. Figure 3 Tertiary Stratigraphic Summary (Chronostratigraphic and Lithostratigraphic Tables sourced from the Millennium Atlas) 5.1 FRIGG SAND INJECTITE LEAD Within the Horda Formation a number of sub-vertical features are identified on seismic within the fallow acreage (Figure 4). Experience from the Harding Field to the northwest strongly suggests that these amplitude features are sand injectites. Using the hydrocarbon accumulations at Harding and Gryphon as analogues these features were considered for assessment as potential targets within the block. Reservoir The anticipated reservoir is the Frigg Sandstone that form part of the reservoir in the Gryphon and Harding North oil fields. In both Gryphon and Harding North the Frigg Sandstone are developed as injectites above the main Balder reservoir and are principally gas bearing. Offset well data has shown these sands can be of excellent reservoir quality with multi Darcy permeability. However the variable development of these sands (Figure 5) means that predicting net to gross ratio prior to drilling is at best problematic. Additionally the seismic reflectivity signature (peak-trough-peak) of the features

6 suggests it represents hard events more likely to represent cemented sandstones rather than good reservoir (Figure 4). Figure 4 Frigg Sand Equivalent example of Sand Injectite Feature within the P209 Licence

7 Figure 5 Correlation of Near Block Offset Wells focusing on the Horda Formation (Flattened on Balder)

8 Hydrocarbons and their Source The source for these leads is the Kimmeridge Clay which the presence of is not considered to be a risk in this area. However both hydrocarbon presence and quality are considered to have significant risk. Using the Harding and Gryphon fields as analogues the fields have a clear AVO response which these leads do not. In addition the Harding oil is heavily biodegraded with low API (~20 o ) which must be assumed for any accumulation at this depth in the area. Trap As no structural closures can be mapped a stratigraphic trapping mechanism must be invoked for these leads. Although the interpretation of sand injectites for these seismic features is considered robust their complex geometric configuration, disjointed nature and the complete lack of any discernible DHI results in the assignment of a very high risk. 6. FURTHER TECHNICAL WORK UNDERTAKEN A rock physics study consisting of a fluid substitution was conducted in an attempt to identify any DHI, eg AVO response from the seismic. The study concluded that both oil and gas could be identified as an increase in amplitude with offset with the highest increase in the presence of gas (Figure 6). No such response was seen in the Tertiary section over the block. Figure 6 Predicted AVO response from fluid substitution analysis (Sele Formation Well 9/23a-30) 7. RESOURCE AND RISK SUMMARY Probabilistic volume estimates have been derived for the four leads and are presented in Table 2. Top and base surfaces were locally mapped for each feature and area-depth plots were generated for each lead as input for gross rock volume and assumed fill to spill (Figure 7). Reservoir properties and formation volume factor (FVF) assumed Harding Field properties and incorporated a wide range of net to gross (20 75%) for input to STOIIP estimates. The STOIIP estimates tabulated below are considered optimistic given the complexity of the structures. All the leads were given an overall chance of success of 10% with the containment being the significant risk element.

9 Lead P90 P50 P10 Injectite Injectite Injectite Injectite Table 2 Frigg Injectite Leads Probabilistic STOIIP Summary (Volumes quoted in MMstb) Figure 7 Summary Map and Seismic Section for the four Frigg Sand Injectite Leads 8. CLEARANCE TAQA Bratani Ltd. confirms that DECC is free to publish this report and that all third party ownership rights (on any contained data and/or interpretations) have been considered and appropriately cleared for publication purposes.