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Reserves and Resource Assessment of the Bentley Field

and Adjacent Acreage

As at 31st December 2015

Xcite Energy Resources plc

John Severs, Tom Gunningham

Terry Pimble

17th March 2016

Reserves and Resource Assessment Report of the Bentley field and Adjacent Acreage

AGR TRACS International Ltd March 2016 i

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

Status Final

Date 17th March 2016

Issued by John Severs

Approved by

Tom Gunningham

Reviewed by Nigel Blott


AGR TRACS International Ltd March 2016 ii

Contents

1. Executive Summary ............................................................................................... 1

2. Introduction .......................................................................................................... 6

3. Database .............................................................................................................. 8

4. Seismic interpretation ........................................................................................... 10

5. Depth conversion .................................................................................................. 13

6. Petrophysical Review of Bentley Wells ..................................................................... 14

7. Bentley Field ........................................................................................................ 17

7.1. Probabilistic forecast of Petroleum Initially In Place ............................................ 17

7.2. Petrel Model .................................................................................................. 20

8. Bentley Reservoir Engineering Data ........................................................................ 26

8.1. PVT Data ...................................................................................................... 26

8.2. Well Test Operations Summary 2012 ................................................................ 26

8.3. Well Test Interpretation Summary ................................................................... 29

8.4. Simulation Model ........................................................................................... 33

8.4.1. General Description .................................................................................. 33

8.4.2. Reference Case results ............................................................................. 36

8.5. Impact on the Range in Recovery Factor ........................................................... 39

8.5.1. Field Life ................................................................................................. 39

8.5.2. Impact of Permeability Uncertainty within the Oil Leg ................................... 39

8.5.3. Impact of Permeability Uncertainty within the Water Leg............................... 40

8.5.4. Impact of Kv/Kh ratio ............................................................................... 40

8.5.5. Impact of Relative Permeability Curves ....................................................... 40

8.5.6. Impact of Residual Oil Saturation ............................................................... 41

8.5.7. Impact of Initial Water Saturation .............................................................. 42

8.5.8. Impact of Oil Viscosity .............................................................................. 43

8.5.9. Impact of Rock Compressibility .................................................................. 43

8.5.10. Basis for Range in Recoverable Volumes ................................................... 43

8.6. Profiles ......................................................................................................... 44

9. Prospects, Blocks 9/4a, 9/8b, 9/9h ......................................................................... 49

9.1. Clement ........................................................................................................ 50

9.2. Chadwick ...................................................................................................... 52

9.3. Cartwright..................................................................................................... 54

9.4. Camm Prospect ............................................................................................. 56


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10. Development Plan ............................................................................................... 59

10.1. First Phase Development (FPD) ...................................................................... 59

10.2. Second Phase Development (SPD) ................................................................. 62

10.3. First and Second Phase CAPEX schedule .......................................................... 63

10.4. First and Second Phase OPEX ........................................................................ 66

10.5. Unescalated and Escalated Costs .................................................................... 67

11. Bentley Development - Economics ........................................................................ 68

11.1. Assumption Register as at 31st December 2015................................................ 68

11.2. McDaniel Price Forecast ................................................................................ 69

11.3. Full Field Results .......................................................................................... 70

11.3.1. FFD Sensitivities ..................................................................................... 73

11.4. First Phase Development – Summary Economics .............................................. 73

11.4.1. FPD Sensitivities..................................................................................... 75

12. Appendix 1 Summary Tables ................................................................................ 76

12.1. Oil and Gas Reserves .................................................................................... 76

12.2. Net Present Value at Alternative Discount Rates ............................................... 77

12.3. Revenue Distribution .................................................................................... 78

12.4. Development Costs ...................................................................................... 79

12.5. Pricing Assumptions ..................................................................................... 80

12.6. Contingent Resources ................................................................................... 81

12.7. Prospective Resources .................................................................................. 82

13. Appendix 2 Glossary ............................................................................................ 83


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Figures Figure 2-1 Bentley Field block location map .................................................................. 7

Figure 3-1 Base map .................................................................................................. 8

Figure 4-1 Synthetic seismogram 9/3-2A .................................................................... 10

Figure 4-2 In-lines through wells 9/3-2A & 4 ............................................................... 11

Figure 4-3 Top Dornoch time map (TWT sec) .............................................................. 12

Figure 5-1 Case 17 top Dornoch depth map (metres) ................................................... 13

Figure 6-1 Bentley well section 9/3-3, 9/3-1 & 9/03b-6 ................................................ 15

Figure 6-2 Bentley well section 9/03b-5, 9/3-2A & 9/3-4 .............................................. 16

Figure 7-1 Bentley field development map with volume polygons .................................. 17

Figure 7-2 Bentley model cross-section showing depositional units ................................ 21

Figure 7-3 Dornoch depositional elements .................................................................. 22

Figure 7-4 Bentley model cross-section showing depositional systems ............................ 22

Figure 7-5 Bentley model cross-section showing depositional elements .......................... 22

Figure 7-6 Bentley model cross-section showing porosity.............................................. 23

Figure 7-7 Saturation curve-fitting algorithms ............................................................. 24

Figure 7-8 PIIP height map ....................................................................................... 25

Figure 8-1 Production history from B6 lateral showing water cut .................................... 27

Figure 8-2 Production history from B6 lateral showing GOR .......................................... 27

Figure 8-3 Late production history from B6/B5 laterals ................................................. 28

Figure 8-4 Derivative plots for PBU 1 & PBU 2 ............................................................. 30

Figure 8-5 ROP vs. WOB drilling data from the 9/03b-6 well ......................................... 31

Figure 8-6 Caliper logs in various Bentley area wells .................................................... 32

Figure 8-7 Location of FPD Wells ............................................................................... 34

Figure 8-8 Location of SPD Wells ............................................................................... 35

Figure 8-9 Profiles from FPD reference case run .......................................................... 38

Figure 8-10 Profiles from reference case SPD Run........................................................ 38

Figure 8-11 Relative permeability curve sensitivities .................................................... 41

Figure 8-12 Saturation/Height function sensitivities ..................................................... 42

Figure 8-13 P90, P50, P10 oil profiles – barrels oil per day ............................................ 45

Figure 9-1 Top Lower Palaeocene sandstone depth map ............................................... 49

Figure 9-2 Line 25740 through Clement ..................................................................... 50

Figure 9-3 Top Lower Palaeocene Sandstone Depth Map, Clement ................................. 51

Figure 9-4 Line 25450 through Chadwick .................................................................... 52

Figure 9-5 Top Lower Palaeocene Sandstone Depth Map, Chadwick ............................... 53

Figure 9-6 Line 24970 through Cartwright .................................................................. 54

Figure 9-7 Top Lower Palaeocene Sandstone Depth Map, Cartwright .............................. 55


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Figure 9-8 Line 3880 through Camm .......................................................................... 57

Figure 9-9 Top Lower Palaeocene Sandstone Depth Map, Camm .................................... 57

Figure 10-1 Bentley Phase 1 MOPU and FSO on location ............................................... 60

Figure 10-2 Bentley FPD well locations ....................................................................... 61

Figure 10-3 Bentley SPD well locations ....................................................................... 62

Figure 10-4 Full field development production facilities schematic .................................. 63

Figure 10-5 Bentley FFD CAPEX schedule – annual and cumulative, escalated (1) ............. 66

Figure 10-6 Bentley full field development OPEX - annual and cumulative, escalated ....... 66

Figure 11-1 Full Field Development economics – P50 undiscounted revenue distribution ... 72

Tables Table 2-1 Process capacities and well type, Bentley Field First Phase Development ............ 6

Table 3-1 Recovered Core from Bentley........................................................................ 9

Table 6-1 Net pay petrophysical averages above OWC ................................................. 15

Table 7-1 Bentley gross rock volume inputs ................................................................ 18

Table 7-2 Bentley PIIP estimate ................................................................................ 18

Table 7-3 Bentley free gas GIIP estimate .................................................................... 19

Table 7-4 Petrel estimate of PIIP ............................................................................... 24

Table 8-1 GOR and bubble point pressure summary ..................................................... 26

Table 8-2 Summary of PBU dates and durations .......................................................... 29

Table 8-3 Full field liquid handling limits ..................................................................... 36

Table 8-4 Life of field drilling schedule, production wells ............................................... 37

Table 8-5 Summary of Recovery from Reference Simulation models .............................. 39

Table 8-6 Impact from sensitivities on permeability in the oil leg ................................... 40

Table 8-7 Impact from sensitivities on permeability in the water leg .............................. 40

Table 8-8 Impact from sensitivities on kv/kh ............................................................... 40

Table 8-9 Impact from sensitivities on relative permeability .......................................... 41

Table 8-10 Impact from sensitivities on residual oil saturation....................................... 41

Table 8-11 Impact from sensitivities on water saturation .............................................. 42

Table 8-12 Impact from sensitivities on oil viscosity ..................................................... 43

Table 8-13 Impact from sensitivities on rock compressibility ......................................... 43

Table 8-14 Range of recoverable volumes from Monte Carlo Simulation, MMstb .............. 43

Table 8-15 Recovery Factors from Monte Carlo Simulation ............................................ 44

Table 8-16 Recoverable volumes from Monte Carlo Simulation and Profiles ..................... 44

Table 8-17 P90 average profiles ................................................................................ 46




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Table 9-1 Clement gross rock volume inputs ............................................................... 51

Table 9-2 Clement PIIP and prospective resources ....................................................... 52

Table 9-3 Clement probability of success .................................................................... 52

Table 9-4 Chadwick gross rock volume inputs ............................................................. 53

Table 9-5 Chadwick PIIP and prospective resources ..................................................... 54

Table 9-6 Chadwick probability of success .................................................................. 54

Table 9-7 Cartwright gross rock volume inputs ............................................................ 56

Table 9-8 Cartwright PIIP and prospective resources .................................................... 56

Table 9-9 Cartwright probability of success ................................................................. 56

Table 9-10 Camm gross rock volume inputs ................................................................ 58

Table 9-11 Camm PIIP and prospective resources........................................................ 58

Table 9-12 Camm probability of success ..................................................................... 58

Table 10-1 Bentley whole crude yield and summary properties ...................................... 59

Table 10-2 Phase 1 CAPEX components and cost estimate basis .................................... 64

Table 10-3 FPD cost changes (2015 RAR vs 2014 RAR, unescalated) ............................. 65

Table 10-4 2015 FPD capitalised lease revision ............................................................ 65

Table 10-5 Unescalated CAPEX and OPEX costs and unit values, Full Field ...................... 67

Table 10-6 Escalated CAPEX and OPEX costs and unit value, Full Field ........................... 67

Table 11-1 McDaniel price forecast January 1st 2016, $/bbl ........................................... 69

Table 11-2 Post-tax economic indicators and oil reserves, Full Field Development ............ 70

Table 11-3 - Relative Cash movements from 31st December 2014 RAR .......................... 71

Table 11-4 Bentley gas reserves, Full Field Development .............................................. 71

Table 11-5 Full Field Development breakeven Brent crude prices for zero NPV10 and NPV0 ....................................................................................................................... 72

Table 11-6 Full Field Development post tax NPVs at alternative discount rates ................ 73

Table 11-7 Full Field Development price sensitivities, discounted and un-discounted NPVs 73

Table 11-8 First Phase Development annual and cumulative CAPEX ............................... 74

Table 11-9 Post-tax economic indicators and oil reserves, First Phase Development ......... 74

Table 11-10 Bentley gas reserves, First Phase Development ......................................... 74

Table 11-11 First Phase Development breakeven Brent crude prices for zero NPV10 and NPV0 ............................................................................................................... 75

Table 11-12 First Phase Development post tax NPVs at alternative discount rates............ 75

Table 11-13 First Phase Development price sensitivities, discounted and un-discounted NPV ....................................................................................................................... 75


AGR TRACS International Ltd March 2016 vii

The Directors Xcite Energy Resources plc 2 Queens Gardens Aberdeen AB15 4YD

17th March 2016

Gentlemen,

Reserves Assessment Report

AGR TRACS International Ltd (“AGR TRACS”) was requested to produce an audit of the hydrocarbon reserves and resources for Xcite Energy Resources plc (“Xcite”) as at 31st December 2015 for their UKCS Northern North Sea blocks, 9/3b, 9/4a, 9/8b and 9/9h.

Xcite currently holds a 100% interest in the licences and the principal asset in these blocks is the Bentley oil discovery located in block 9/3b. Eight wells have been drilled in this field including the 6Z horizontal sidetrack and the 9/03b-7/7Z appraisal well drilled as part of a comprehensive Extended Well Test (“EWT”) conducted in 2012. This confirmed that the Bentley reservoir could achieve sustained commercial flow rates as well as proving the viability of Xcite’s multilateral well drilling and completion strategy as well as separation and dehydration processes.

Further refinements to well design were made in 2015 resulting in slim hole well designs being replaced by full hole well architecture. In addition, a quantitative review of drilling and completion times, cross-referenced to the Rushmore North Sea drilling database, was undertaken resulting in time savings of 250 jack-up days and 56 well workover days in the First Phase Development. This results in an accelerated well delivery program for first phase production and as a result, production volumes in the first five years of field life have increased by 0.74 MMbbls (P90), 1.21 MMbbls (P50) and 2.27 MMbbls versus last year’s Report.

Cost estimates for the Bentley development were revised by Xcite towards the end of 2015 and early 2016 using vendors’ submissions of updated cost estimates, including re-estimated rig rates and overall drilling costs. The industry is still in the process of adjustment to low oil prices and considerable downward pressure remains at the time of this report. In parallel with the CAPEX review, OPEX costs were also updated resulting in OPEX costs being reduced by 11.2%. Key reductions are noted in well engineering, operations support services (supply boats, helicopter, communications etc.) and production operations (including fuel costs).

On 16th March 2016 the Supplementary Charge rate was further reduced from 20% to 10%, effective 1 January 2016, and this change is reflected in the figures reported here.

A summary of the key revisions to First Phase Development CAPEX costs is provided overleaf. Further discussion of cost revisions are contained in the Development Plan section of this report.


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FPD CAPEX Item % Change vs 2014 RAR Contingency (1)

Mobile Offshore Production Unit -23.7% 15%

Gas Import Line -10.4% 20%

Sub-total Facilities -13.7%

Wells -23.0% 9%

Abex -0.1% 20%

Total -19.2%

2015 FPD CAPEX revisions (1) Applied to non-lump sum costs

Reserves estimates for the whole Bentley Field are reported below. Only volumes that are both economic and produced within the first 35 years of field facilities design life are included. Reserves have been revised up by 2 MMbbls for the P90 and P50 production cases and 2.2 MMbbls to P10 reserves; this is primarily attributable to the faster well delivery schedule resulting in additional production within the fixed 35 year facilities life which is used as the cut-off point between reserves and Contingent Resources. McDaniel’s price forecast dated 1st January 2016 was used for the evaluation, which is significantly reduced from the forecast used in the previous year.

Bentley Oil Reserves

NPV10 $MM

NPV0 $MM

Reserves MMstb

NPV10 $/bbl

NPV0 $/bbl

IRR

P90 2,070.1 7,292.2 235.9 8.8 30.9 35.0%

P50 2,496.9 9,134.1 267.3 9.3 34.2 38.8%

P10 2,866.9 10,991.9 298.0 9.6 36.9 41.1%

Post-tax economic indicators and oil reserves, full field development

A full field economic evaluation incorporating first and second phase developments (“FPD”, “SPD”) is positive for all production cases. IRR values lie in the range 35% to 41%, with production remaining economic up to 35 years facilities life for all cases and beyond 35 years for the P50 and P10 cases.

Comparing the NPV of the Full Field Development with the 2014 RAR, the negative impact of the lower oil price assumption is outweighed by the effect of the reduced costs and the reduced supplementary charge, so the NPV increases. NPV10 increases from $2,255 million to $2,497 million, while NPV0 increases from $8571 million to $9134 million. These figures are broken down and compared in the report (see Table 11-3).


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For the P50 case, the breakeven Brent crude price (when NPV10 equals zero) is $40.53/bbl; the corresponding breakeven Brent crude price on an undiscounted basis (when NPV0 equals zero) is $34.08/bbl. The 12% negative differential for Bentley versus Brent crude has been retained.

Case Breakeven Brent Price at 10% Discount Rate $/bbl (1)

Breakeven Brent Price at 0% Discount Rate $/bbl (2)

P90 $44.87 $38.16

P50 $40.53 $34.08

P10 $37.39 $30.86

Full Field Development breakeven Brent crude prices for zero NPV10 and zero NPV0, post-tax basis

(1) The corresponding price realizations for Bentley crude using a 12% (negative) differential and 10% discount rate are P90 $39.49, P50 $35.67 and P10 $32.90. (2) The corresponding price realizations for Bentley crude using a 12% (negative) differential and 0% discount rate are P90 $33.6, P50 $30.0 and P10 $27.2.

Included in the evaluation are gas reserves derived from solution gas and gas caps in Bentley East that are planned for use as fuel during production operations. It is assumed that 90% of gas produced is utilized for process heat and power.

Bentley Gas Reserves BCF P90 P50 P10

Bentley Gas Reserves 22.9 35.9 49.4

Bentley first and second phase development gas reserves

Xcite announced on the 18th February 2016, that following discussions with the Oil & Gas Authority (“OGA”), the Secretary of State for the Department of Energy and Climate Change has extended the P.1078 licence containing the Bentley field until 30 June 2017. This licence extension is intended to assist Xcite’s current process to secure the financing required for the approval of its Bentley Field Development Plan. Xcite has received indicative proposals for development funding, which remain subject to agreement of commercial structuring and finalisation of due diligence, and is currently in detailed discussions to progress these proposals which would enable a fully funded first phase development plan to be submitted to the OGA in 2016. With appropriate maintenance and replacement practices, facilities, infrastructure and wells are capable of service in a North Sea environment beyond 35 years. However, in this report, production beyond the 35 years facilities service life has been classed as Contingent Resources.

Under the evaluation parameters used in this report, Bentley production remains economic for a further 15 years (P50 and P10 cases). These volumes are reported as Contingent Resources.


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Mean MMstb P90 MMstb P50 MMstb P10 MMstb

Contingent Oil Resources 12.2 0.0 9.3 28.1

Bentley first and second phase contingent oil resources

Block Mean BCF P90 BCF P50 BCF P10 BCF

9/3b 1.4 0.0 0.9 3.3

Bentley first and second phase contingent gas resources (1) (1) Contingent Resources are calculated at 90% of gas production

Xcite have entered into a farmout agreement regarding Blocks 9/4a, 9/8b and 9/9h (i.e. excluding Block 9/3b containing the Bentley field) in which the farminee has an option to acquire a 40% interest in the blocks in exchange for further technical evaluation, and to acquire a further 10% subject to additional works being performed. At the time of this report, the agreement had not been approved by DECC and associated prospective resources are therefore reported on a 100% gross basis. Excluded from this report are three minor prospects in Block 9/3b – Brunel, Prospect A and Prospect B. This follows from a field determination boundary review for the Bentley field completed in 4Q 2015 which resulted in the area containing the prospects being relinquished by Xcite.

In 2012 Xcite acquired two 3D surveys, “Q-9 2011 Bruce” and “NVG11M”. The surveys encompass the area to the south and east of the Bentley. These were used to map the prospects in blocks 9/4a, 9/8b and 9/9h. In January 2013, Xcite were awarded License P.1979 containing four prospects located in 9/4a, 9/8b and 9/9h. Prospective Resources associated with these as yet undrilled structures are detailed below and are unchanged from the Reserves Assessment Report as of 31st December 2014, excepting that targets associated with Block 9/3b are no longer reported. This follows relinquishment of part of Block 9/3b (i.e. excluding Block 9/3b containing the Bentley field) in October 2015 as a result of an updated field determination boundary for the Bentley field.

Prospect Block Mean MMstb

P90 MMstb

P50 MMstb

P10 MMstb POS

Clement 9/4a 4.7 0.9 3.1 10.2 0.21

Chadwick 9/4a 30.6 10.5 24.6 57.8 0.21

Cartwright 9/4a 19.3 8.6 16.9 33.2 0.16

Camm 9/8b, 9/9h 15.0 2.6 9.4 34.6 0.18

Prospective oil resources

_____________________________________________________


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This review was undertaken by a team of AGR TRACS professional petroleum engineers and geoscientists based on data supplied by Xcite. The data comprised details of licence and acreage interests, exploration geological and geophysical data, interpreted data, and technical presentations. AGR TRACS have exercised due diligence on all technical information supplied.

In estimating petroleum resources we have used the standard petroleum engineering techniques. These estimates are based on the joint definitions of the Society of Petroleum Engineers, the COGEH Handbook, the World Petroleum Congress, the American Association of Petroleum Geologists and the 2011 PRMS (Petroleum Resources Management System).

Qualifications

AGR TRACS International Limited is an independent consultancy specialising in petroleum reservoir evaluation and economic analysis. Except for the provision of professional services on a fee basis, AGR TRACS have no commercial arrangement with any other person or company involved in the interests that are the subject of this report.

The project was managed by Nigel Blott (B.Sc.), SPE Member and General Manager of AGR TRACS, Guildford. Mr Blott, a petroleum engineer, has over 30 years’ experience in the industry. Since it was founded in 1992, AGR TRACS has conducted valuations for many energy companies and financial institutions. The Reserves and Resources volumes were approved and signed off by Mr Tom Gunningham (C.Eng. MEI.) who is a Chartered Petroleum Engineer, member of the Energy Institute and Independent Qualified Reserves Auditor compliant with COGEH requirements.

Basis of Opinion

The evaluation presented in this report reflects our informed judgement based on accepted standards of professional investigation, but is subject to generally recognised uncertainties associated with the interpretation of geological, geophysical and subsurface reservoir data. It should be understood that any evaluation, particularly one involving exploration and future petroleum developments, may be subject to significant variations over short periods of time as new information becomes available.

Yours faithfully,

Nigel Blott

AGR TRACS International Ltd


AGR TRACS International Ltd March 2016 1

1. Executive Summary

AGR TRACS International Ltd (“AGR TRACS”) was requested to produce an audit of the hydrocarbon reserves and resources for Xcite Energy Resources plc (“Xcite”) as at 31st December 2015 for their UKCS Northern North Sea blocks, 9/3b, 9/4a, 9/8b and 9/9h.

Xcite holds a 100% interest in the licences and the principal asset in these blocks is the Bentley oil discovery located in block 9/3b. Eight wells have been drilled in this field including the 6Z horizontal sidetrack and the 9/03b-7/7Z appraisal well drilled as part of a comprehensive Extended Well Test (“EWT”) conducted in 2012. This confirmed that the Bentley reservoir could achieve sustained commercial flow rates as well as proving the viability of Xcite’s multilateral well drilling and completion strategy as well as separation and dehydration processes.

Further refinements to well design were made in 2015 resulting in slim hole well designs being replaced by full hole well architecture. In addition, a quantitative review of drilling and completion times, cross-referenced to the Rushmore North Sea drilling database, was undertaken, as well as the inclusion of a learning curve based on multiple wells in the campaign. FPD total rig time savings versus 2014 RAR are estimated at 250 jack-up days and 56 well workover days.

Cost estimates for the Bentley development were revised by Xcite towards the end of 2015 and early 2016 using vendors’ submissions of updated cost estimates, including re-estimated rig rates and overall drilling costs. CAPEX and OPEX cost revisions used in this report were derived from this exercise. The industry is still in the process of adjustment to low oil prices and considerable downward pressure remains at the time of this report. Revisions to FPD CAPEX costs are reported below together with contingency rates for non-lump-sum cost components.

On 16th March 2016 the Supplementary Charge rate was further reduced from 20% to 10%, effective 1 January 2016, and this change is reflected in the figures reported here.

FPD CAPEX Item % Change vs 2014 RAR

Contingency (1)




Wells -23.0% 9%

Abex -0.1% 20%

Total -19.2%

FPD cost changes (2015 RAR vs 2014 RAR, unescalated) (1) Applied to non-lump-sum costs



FPD Capitalised Lease Item % Change vs 2014 RAR

Contingency

Floating Storage and Offtake Vessel (converted to a lease and incorporated into OPEX)

+3.8% 11%

2015 FPD capitalised lease revision

In parallel with the CAPEX review and update, OPEX costs were also updated, resulting in OPEX costs being reduced by 11.2%. Key reductions are noted in well engineering, operations support services (supply boats, helicopter, communications etc.) and production operations (including fuel costs). Changes in the FSO lease rate have also been included; the inclusion of FEED engineering costs in the FSO lease has increased the capital element by 3.8%. As a long lease item, the capital element is claimable against tax at the commencement of the lease on mobilisation to the field. The financing cost of the lease is not claimable against supplementary charge. The FSO lease day rate is fixed for the 15 year term of the lease and so that element is not escalated within the OPEX costs.

Reserves estimates for whole field development are reported below. Only volumes that are both economic and produced within the first 35 years of field facilities design life are included. Reserves have been revised up by 2 MMbbls for the P90 and P50 production cases and 2.2 MMbbls to P10 reserves; this is primarily attributable to the faster well delivery schedule resulting in additional production within the fixed 35 year facilities life which is used as the cut-off point between reserves and Contingent Resources. McDaniel’s price forecast dated January 1st 2016 was used for the evaluation, which is significantly reduced from the forecast used in the previous year.


NPV10 $MM

NPV0 $MM

Reserves MMstb

NPV10 $/bbl

NPV0 $/bbl

IRR

P90 2,070.1 7,292.2 235.9 8.8 30.9 35.0%

P50 2,496.9 9,134.1 267.3 9.3 34.2 38.8%

P10 2,866.9 10,991.9 298.0 9.6 36.9 41.1%

Full Field Development economic indicators and oil reserves, post-tax basis

Full field economics comprising first and second phase developments (“FPD”, “SPD”) is positive for all production cases. IRR values lie in a range between 34%-41%, with production remaining economic up to 35 years facilities life for all cases and beyond 35 years under the P50 and P10 cases.

Comparing the NPV of the Full Field Development with the 2014 RAR, the negative impact of the lower oil price assumption is outweighed by the effect of the reduced costs and the reduced supplementary charge, so the NPV increases. NPV10 increases from $2,255 million to $2,497 million, while NPV0 increases from $8571 million to $9134 million. These figures are broken down and compared in the table below.



P50 Undiscounted Full Field NPV0 P50 Discounted Full Field NPV10

$MM $MM Comment $MM $MM Comment

2014 NPV0 8,571 Reference 2014 NPV10 2,255 Reference

Revenue (3,192) Reduced Revenue (883) Reduced

Drillex 742 Improved Drillex 320 Improved

Facilities Capex 274 Improved Facilities Capex 209 Improved

Opex 608 Improved Opex 135 Improved

Abex 16 Improved Abex 0 Improved

Corporation Tax 503 Improved Corporation Tax 99 Improved

Supplementary Charge 1,614 Improved Supplementary

Charge 361 Improved

NPV0 563 563 Increased NPV10 242 242 Increased

2015 NPV0 9,134 2015 NPV10 2,497

Relative Cash movements from 31st December 2014 RAR

For the P50 case, the breakeven Brent crude price (when NPV10 equals zero) is $40.53/bbl; the corresponding breakeven Brent crude price on an undiscounted basis (when NPV0 equals zero) is $34.08/bbl. The 12% negative differential for Bentley versus Brent crude has been retained.



P90 $44.87 $38.16

P50 $40.53 $34.08

P10 $37.39 $30.86

Full Field Development breakeven Brent crude prices for zero NPV10 and zero NPV0, post-tax basis

(1) The corresponding price realizations for Bentley crude using a 12% (negative) differential are P90 $39.49, P50 $35.67 and P10 $32.90. (2) The corresponding price realizations for Bentley crude using a 12% (negative) differential and 0% discount rate are P90 $33.6, P50 $30.0 and P10 $27.2.



Included in the evaluation are gas reserves derived from solution gas and gas caps in Bentley East that are planned for development for use as fuel during production operations. It is assumed that 90% of gas produced is utilized for process heat and power.


Bentley Total Gas 22.9 35.9 49.4

Bentley gas reserves, Full Field Development

Xcite announced on the 18th February 2016, that following discussions with the Oil & Gas Authority (“OGA”), the Secretary of State for the Department of Energy and Climate Change has extended the P.1078 licence containing the Bentley field until 30 June 2017. This licence extension is intended to assist Xcite’s current process to secure the financing required for the approval of its Bentley Field Development Plan. Xcite has received indicative proposals for development funding, which remain subject to agreement of commercial structuring and finalisation of due diligence, and is currently in detailed discussions to progress these proposals which would enable a fully funded first phase development plan to be submitted to the OGA in 2016. It is recognised that with appropriate maintenance and replacement practices, facilities, infrastructure and wells are capable of service in a North Sea environment beyond 35 years. However, in this report production beyond the 35 years facilities service life has been classed as Contingent Resources. Under the evaluation parameters used in this report, Bentley production remains economic for a further 15 years (P50 and P10 cases). These volumes are reported as Contingent Resources.

Mean MMstb P90 MMstb P50 MMstb P10 MMstb

Contingent Oil Resources 12.2 0.0 9.3 28.1

Bentley first and second phase contingent oil resources

Mean BCF P90 BCF P50 BCF P10 BCF

Contingent Gas Resources 1.4 0.0 0.9 3.3

Bentley first and second phase contingent gas resources (1)

(1) Contingent Resources are calculated at 90% of gas production

In 2012 Xcite acquired two 3D surveys, “Q-9 2011 Bruce” and “NVG11M”. The surveys encompass the area to the south and east of the Bentley. These were used to map the prospects in blocks 9/4a, 9/8b and 9/9h. In January 2013, Xcite were awarded License P.1979 containing four prospects located in 9/4a, 9/8b and 9/9h. Prospective Resources associated with these as yet undrilled structures are detailed below and are unchanged from the Reserves Assessment Report as of 31st December 2014, excepting that targets associated with Block 9/3b are no longer reported. This follows relinquishment of part of block 9/3B (i.e. excluding Block 9/3b containing the Bentley field) in October 2015 as a result of an updated field determination boundary for the Bentley field.




P90 MMstb

P50 MMstb

P10 MMstb POS

Clement 9/4a 4.7 0.9 3.1 10.2 0.21

Chadwick 9/4a 30.6 10.5 24.6 57.8 0.21

Cartwright 9/4a 19.3 8.6 16.9 33.2 0.16

Camm 9/8b, 9/9h 15.0 2.6 9.4 34.6 0.18

Prospective oil resources



2. Introduction

AGR TRACS were requested to produce an independent audit of reserves and resources by Xcite Energy Resources plc (“Xcite”) for its Bentley Field and adjacent exploration prospects.

This report updates the AGR TRACS Reserves Report with an effective date of 31st December 2014. No new field data has been acquired since that report although an updated drilling schedule was supplied by the company following from revised well time estimates. All production wells whether of standard or extended length will now be constructed using full-hole well architecture. Data and reports explaining and supporting revisions to CAPEX and OPEX cost estimates were also provided.

The existing dataset included the results of the Extended Well Test (“EWT”) and the processing and interpretation of a high quality broad bandwidth geostreamer 3D seismic survey completed in November 2012. This confirmed the Bentley Field to be one continuous four-way dip-closed structure.

No changes to Phase 1 of the facilities component of the Bentley field development plan have been made and planned capacities are shown in Table 2-1 below:

Item 2015 RAR

Total Liquids Capacity 270 Mblpd Of which: Oil 45 Mbopd Water 265 Mbwpd Number of producing oil wells (platform) 21 Max number of lateral sections per well 4 Water injection wells 3

Table 2-1 Process capacities and well type, Bentley Field First Phase Development

The Bentley field is located in Block 9/3b (licence P.1078) in the Northern North Sea, 160km east of the Shetland Isles and separated from the Statoil operated Mariner and EnQuest operated Kraken fields, both currently under development. All field discoveries are heavy oil and exhibit similar reservoir characteristics - low Gas Oil Ratio ("GOR"), low pressure and the requirement for artificial lift.



Figure 2-1 Bentley Field block location map

The Bentley field was discovered in 1977 by Amoco by well 9/3-1. Oil was found in the early Eocene/late Palaeocene age Dornoch sandstone at a depth of 3763ft MD. An oil water contact was seen at 3844ft showing a total oil column of 81ft. A drill stem test (DST) of the interval 3764ft MD to 3827ft MD failed to flow but 2 barrels of oil (11.8 API) were reverse circulated out. Presence of oil was confirmed by the subsequent appraisal wells 9/3-2A, & 4. Only 9/3-3 failed to find oil in the Dornoch and has since been mapped on a separate closure from the Bentley Field. Xcite took over operatorship of the licence of the 9/3b block (P.1078) in 2003 and drilled two further successful appraisal wells, 9/03b-5 and the deviated well with a horizontal sidetrack 9/03b-6 / 6Z, prior to the EWT completed in September 2012 (9/03b-7 /7z).

In 2012, blocks 9/4a, 9/8b and 9/9h were awarded to Xcite under the 27th Seaward Licensing Round which took effect from 1st January 2013 (Licence P.1979). These blocks contain a number of exploration prospects which are included in this evaluation. In January 2015, Xcite relinquished adjacent acreage in UKCS blocks 9/3c (P.1760) and 9/3d (P.1761), and, following a field determination boundary for the Bentley field with the OGA that was completed in October 2015, a portion of Block 9/3b containing the Brunel prospects and prospects “A” and “B” was relinquished.



3. Database

Xcite provided a comprehensive geological and geophysical database over the Bentley Field. The field is covered by the “BBK2011”, 3D seismic survey that was shot by PGS in 2011 using their latest dual sensor streamer. This produced an increase in data quality compared to the previous CGG survey. In addition, Xcite acquired two further 3D surveys utilizing common PGS technology - “Q-9 2011 Bruce” and “NVG11M” - that encompass the area to the south and east (Figure 3-1). These were used to map the prospects in blocks 9/4a, 9/8b and 9/9h. The surveys were provided in the form of an IHS Kingdom project that was produced by Senergy and updated by Xcite. It included interpreted horizons, faults, time grids, depth grids and well data.

Figure 3-1 Base map

A extensive suite of data was provided for the Bentley wells that included end of well reports, test reports, composite logs and check shot data. In addition, a comprehensive set of reports were provided describing the interpretation and modelling of the Bentley field. These included the following:

• Bentley Field Petrophysical Update 2014. Senergy August 2014 • Bentley Field Seismic Review of Reservoir. S Crombie November 2013 • Depth conversion for the 2014 static model. S Crombie 18 November 2014 • Bentley Oil Field Static Reservoir Model Petrel. A Upton February 2015



• Petrographic Study of Cuttings Samples, Dornoch Formation, Bentley Field. AM Geos Ltd

Only very limited core data has been recovered from any of the Bentley wells over the reservoir section due to the friable characteristics of the reservoir rock; a table of recovered core is included below.

Table 3-1 Recovered Core from Bentley

Digital well logs (both raw and interpreted) were provided as LAS files by Xcite. These were loaded into the Kingdom project to view the reservoir correlation and the quality of the petrophysical analysis.

A Petrel model was provided for the Bentley field. It was based on one of the latest top structure depth surfaces produced by Xcite. This was incorporated into a new full field dynamic simulation model written in Roxar’s Tempest software. This formed the basis of the recovery estimate from the horizontal multi-laterals planned for the field development.

Extensive information was provided on well design and costs, project execution planning, field development planning plus associated engineering and cost data for the Mobile Offshore Production Unit (MOPU), Floating Storage and Offtake vessel (FSO) and utilities.



4. Seismic interpretation

The Bentley field has been remapped on the PGS 2011 3D seismic survey. Senergy have produced synthetic seismograms for the wells to make a top reservoir well tie. The example synthetic seismogram, 9/3-2A, (Figure 4-1) from the central part of the field shows a reasonable tie of seismic reflections to formation tops. Unfortunately, the top Dornoch does not produce an independent reflection but forms part of the following lag from a lower Balder event above. In 9/3-2A, the top Dornoch is located close to the zero crossing and this was picked by Senergy as top reservoir over the field. In addition, the Top Lista which forms the base of the reservoir was picked (Figure 4-2).

Figure 4-1 Synthetic seismogram 9/3-2A



Figure 4-2 In-lines through wells 9/3-2A & 4

A review of the horizon interpretation showed that the top Dornoch reflection could be picked and mapped on the zero crossing with reasonable reliability over most of the area of the field (Figure 4-3). The main area of pick uncertainty was to the northeast of 9/3-1. Data quality here is poor and, as this formed the crest of the structure, an alternative interpretation was undertaken.



Figure 4-3 Top Dornoch time map (TWT sec)



5. Depth conversion

The depth conversion of the Bentley Field was completely revised (by Crombie 2014) and incorporated into the previous report.

A review of the depth maps from this exercise showed that Bentley East was connected at the OWC to the Bentley core area on all the various depth conversions. As a result, Bentley East was included as part of the Bentley Field (Figure 5-1).

Further studies on the strong seismic amplitude anomalies seen at culminations at the Bentley East support the interpretation of localised gas caps. Subtraction of near trace stack amplitude from far trace stack amplitude showed an amplitude versus offset (AVO) anomaly with stronger amplitudes developed at longer offsets. Forward modelling of these amplitudes showed that gas should be detectable if the column is greater than 5 ft.

Figure 5-1 Case 17 top Dornoch depth map (metres)

Gas cap

OWC



6. Petrophysical Review of Bentley Wells

In 2014, Xcite provided an updated petrophysical report in which sonic, density and gamma logs had been normalised for all wells.

9/03b-7 and 9/03b-7Z were logged without the use of traditional nuclear tools due to their extended horizontal sections. Porosity was derived from both the sonic log and the NMR log. Both wells are near horizontal and as such, severe anisotropy is seen in the resistivity and to a lesser extent in the sonic log.

Reservoir parameters for all wells were reviewed, with the earlier 9/03b-6 pilot well providing the most comprehensive and reliable dataset. The reservoir parameters derived from logs prior to 9/03b-7 / 7Z provide a valid and robust suite of reservoir properties.

Log data

The supplied log data from 9/03b-6 pilot well was sufficient to allow a petrophysical review of volume of clay, porosity and water saturation in the Dornoch formation. Due to the unconsolidated condition of the reservoir sands, no ancillary data such as routine or special core analysis was available to allow correlation of the volume of clay, porosity and water saturation.

Log edits

The pilot hole 9/03b-6 was drilled with an in-gauge hole due to advances in mud type, and this well is used as the key well to the petrophysical review.

Volume of clay

Calculated from a simple GR model, the reservoir is relatively clean, containing a background shale content of 5%. Occasionally the well-developed sands grade to siltstones, but are not volumetrically significant.

Porosity

Both sonic and neutron density porosities were calculated using standard textbook values for the matrix and fluid properties. In general, the average effective porosity for the reservoir interval for all wells is 32.2%. In the wells drilled prior to 9/03b-6, which experienced significant washouts, a combination of sonic and density data was used to generate the total porosity. Where no sonic log was available, a simple average density was assumed in areas of significant washout. This average density was derived on a well by well basis from the substantial water leg sands where the borehole is in good condition.

Water saturation

A simple Archie method was used to calculate water saturation. Rw and “m” were derived from a Pickett plot, while “a” and “n” were assumed to be 1 and 2 respectively. Water saturations are low in good quality reservoir. At full hydrocarbon saturation in the best reservoir, the irreducible water saturation as calculated by Archie can be as low as 5%, as illustrated in well 9/03b-5. Average saturation for the net pay interval for all wells is 8.5% and is entirely reasonable given the quality of the reservoir.

Petrophysical averages

Reservoir and net pay cut-offs are defined as follows: net reservoir is above 10% porosity and below 30% volume of clay, net pay uses the above net reservoir values and includes an additional water saturation cut-off of 50%.



Well Gross ft Net ft Net/gross PHIE Sw

9/3-1 81.0 77.0 0.950 0.330 0.060

9/3-2A 92.0 81.0 0.880 0.330 0.100

9/3-4 84.0 58.8 0.700 0.330 0.140

9/03b-5 84.0 81.5 0.970 0.330 0.050

9/03b-6 114.1 113.0 0.990 0.300 0.090

Sum/Ave. (wells with pay) 455.1 411.1 0.903 0.322 0.085

Table 6-1 Net pay petrophysical averages above OWC

Cut-offs PHIE<0.1, VCL>0.3, Sw>0.5

Averages corrected to true vertical depth.

Sums and averages used in this report have been calculated on the entire reservoir section as opposed to just the net pay section. Significant wash outs within the oil leg of the reservoir have been replaced by an average porosity value of 36% in the supplied petrophysical interpretation. All horizontal wells have been excluded from the averages to avoid sample bias introduced by geosteering the well into the best reservoir quality.

Figure 6-1 Bentley well section 9/3-3, 9/3-1 & 9/03b-6



Figure 6-2 Bentley well section 9/03b-5, 9/3-2A & 9/3-4

Oil Water Contact

A field wide oil water contact has been identified at 1136m (3727 ft TVDSS) and has been intersected by a number of wells, namely 9/3-1, 9/3-2A, 9/3-4, 9/03b-5 and 9/03b-6.

Increased VCL



7. Bentley Field

7.1. Probabilistic forecast of Petroleum Initially In Place

Based on the proposed development scheme and PIIP, technically recoverable oil reserves for the Bentley field were calculated probabilistically in three areas, namely FPD, SPD south and SPD East (Figure 7-1):

Figure 7-1 Bentley field development map with volume polygons

Legend



Gross rock volumes (“GRV”) were calculated from each of the 24 depth maps within the three segments of the field using an OWC of -3727 ft TVDSS. Based on the area of the seismic amplitude anomalies, gas/oil contacts were estimated and the GRV calculated for the gas legs present in the FPD and SPD East areas. These GRVs were subtracted from the total GRV in these segments to calculate the GRV for the oil leg for each map. The average of these GRVs was set to the mean in a normal distribution with the standard deviation used to produce the range for the GRV assumption in the probabilistic forecast of PIIP (Table 7-1). In addition, GRVs were calculated in the areas where the top reservoir exceeds 60 feet above the OWC. This has been defined as the “Developable Oil Area”.

Bentley GRV Minimum m3*106

Average m3*106

Maximum m3*106

Standard Deviation

Bentley FPD Oil 297.20 343.51 400.73 27.22

Bentley SPD South Oil 96.14 112.36 134.99 9.23

Bentley SPD East Oil 56.34 115.17 220.33 38.28

Bentley FPD Developable Oil 207.73 236.27 274.04 17.76

Bentley SPD South Developable Oil 48.68 59.24 72.93 5.87

Bentley SPD East Developable Oil 20.22 71.54 177.48 37.09

Bentley Total (Probabilistic) 486.32 572.13 702.83 58.90

Table 7-1 Bentley gross rock volume inputs

Average reservoir properties (net/gross ratio, porosity and water saturation) were based on the petrophysical averages from the Bentley wells (Table 6-1). The PIIP for both the Phase 1 and Phase 2 areas are given in Table 7-2 and the GIIP in Table 7-3.

Bentley PIIP MMstb Mean P90 P50 P10

Bentley FPD Oil 527.0 447.6 525.7 607.5

Bentley SPD South Oil 172.7 146.1 172.2 199.9

Bentley SPD East Oil 175.2 111.7 167.1 251.0

Bentley FPD Developable Oil 363.1 309.1 362.7 417.5

Bentley SPD South Developable Oil 91.0 76.1 90.6 106.7

Bentley SPD East Developable Oil 108.4 51.0 98.2 182.1


Table 7-2 Bentley PIIP estimate



Bentley GIIP BCF Mean P90 P50 P10

Bentley Phase 1 Free Gas 1.1 0.9 1.1 1.4

Bentley Phase 2 Free Gas 12.0 5.1 12.0 19.0


Table 7-3 Bentley free gas GIIP estimate



7.2. Petrel Model

The Petrel geological model of the Bentley Field, used for the dynamic simulation, was completely rebuilt in 2014 and the results incorporated into the April 2015 Reserves Assessment Report, effective 31st December 2015. No further changes have been made and this section restates key aspects of the Bentley geological model.

The structure is based on the latest Xcite mapping of the top Dornoch and top Lista which form the top and base of the reservoir. The area is structurally simple and no significant faults have been mapped within the field, and none are expected to compartmentalise the reservoir. A set of intra-reservoir surfaces were mapped; these were interpreted as stratigraphic markers, representing progradational units, younging towardtops the East.

The structural simplicity removes the factor that usually constrains the design of model grids within Petrel. Consequently Xcite has chosen to build a model that is intended to be optimised for dynamic simulation. No faults are included and the grid is entirely constructed from vertical pillars based on a 20x20m cell size.

The depth conversion model provided a range of 20 depth grids for the top Dornoch to represent the uncertainty in the gross rock volume (GRV). Case 17 was chosen as the base case, and was incorporated into the model as the top of the grid. This was considered a slightly optimistic base case with a GRV above the OWC 2.2% greater than the total field average but more significantly, 6% above the average for the FPD. The surface was tied to well picks, with additional control being provided by data derived from the AziTrack tool, which indicates the distance to a bed boundary in high angle wells.

The Top Lista depth surface defines the base of the grid while an arbitrary boundary controls the area. The uppermost 15 ft has been defined as an Upper zone while the remainder of the model forms an undivided Lower zone; the mapped progradational surfaces have not been incorporated as explicit zones and no segments were defined. Finally, the upper zone was divided into three layers, each 5 ft thick, while the lower zone was proportionally divided into 90 layers.

Well 9/3-2AW E

Upper zone

Depositional units

Lower zone

OWC



Figure 7-2 Bentley model cross-section showing depositional units

The intra-reservoir horizons were used to define four separate depositional units (Figure 7-2) which subsequently control the facies modelling process.

The Bentley Field depositional model (AM Geos Ltd, 2015) has evolved from the integration of a depositional facies model with seismic stratigraphic analysis (Crombie, 2014). The model is based on the shelf delta setting of the Dornoch sequence, and a facies association for the Bentley area was defined as described in Figure 7-3. Well data have been interpreted to derive facies logs (depositional elements), which were convolved to yield a depositional system log. Both logs were upscaled into the Petrel grid, and subsequently stochastically distributed to generate a three-dimensional facies model:

• The depositional system property was distributed within the seismically defined depositional units (Figure 7-4).

• The depositional elements were then distributed with the corresponding depositional system as control (Figure 7-5).

The facies modelling process was constrained by several controlling trends and limits that were defined from seismic.



Figure 7-3 Dornoch depositional elements

Figure 7-4 Bentley model cross-section showing depositional systems

Figure 7-5 Bentley model cross-section showing depositional elements

A field-wide oil-water contact was defined at -3727 ft TVDss, while two gas caps were defined in the South Eastern part of the field based on seismic response; free gas has not been encountered in any of the reservoir sections of the wells drilled to date.

Well 9/3-2AW E

OWC

Well 9/3-2AW E

OWC



Petrophysical properties were then populated within the model:

• Porosity: upscaled from log data and distributed stochastically within each facies (Figure 7-6).

• Permeability: distributed stochastically within each facies using Gaussian random

function simulation, based on log normal distributions of permeability, and applying porosity as a secondary control.

• Net-to-gross: assigned based on facies-specific porosity cut-offs.

• Saturation: assigned according to an algorithm derived from a curve-fitting exercise based on porosity and height above the water contact (Figure 7-7).

Figure 7-6 Bentley model cross-section showing porosity

Well 9/3-2AW E

OWC



Figure 7-7 Saturation curve-fitting algorithms

The Petrel model provided to AGR TRACS was interrogated to calculate PIIP to compare with that calculated by probabilistic analysis (Table 7-4). Overall the total PIIP from Petrel was close to the probabilistic forecast P50 (Petrel 894 MMstb, P50 881 MMstb. However, as expected the Petrel FPD case was towards the upper end of the probabilistic distribution (P22). This was due to the depth surface selected for Petrel having a higher than average GRV in the FPD combined with better than average reservoir properties. PIIP in the SPD South was close to the P90 forecast due to lower GRV and poorer reservoir properties than average.

Oil zones Bulk volume m3*106

Net volume m3*106

Pore volume m3*106

HCPV oil m3*106

PIIP MMstb

Bentley FPD Oil 358.13 354.80 111.68 94.99 572.86

Bentley SPD South Oil 115.50 110.05 33.48 24.41 147.24

Bentley SPD East Oil 126.25 124.82 37.89 28.76 173.46

Bentley Total 599.88 589.66 183.05 148.17 893.55

Table 7-4 Petrel estimate of PIIP

A PIIP height map was produced to show the location of the greatest density of PIIP across the field (Figure 7-8). This clearly shows the bulk of the reserves present in the northern part of the field encompassed by the FPD. It also shows the limited connection of Bentley East to the rest of the field.

Height above contact (ft)

Water saturation



Figure 7-8 PIIP height map

413000 414000 415000 416000 417000 418000 419000 420000 421000 422000

413000 414000 415000 416000 417000 418000 419000 420000 421000 422000

6636

000

6638

000

6640

000

6642

000

6644

000

6646

000

6648

000

6650

000

66360006638000

66400006642000

66440006646000

66480006650000

0 0.5 1 1.5 2 2.5km

55

45

35

25

15

5

60



8. Bentley Reservoir Engineering Data

This section has been updated for incorporation of additional work completed by Xcite during 2015. This features:

• An updated drilling schedule with modest acceleration of drilling times • A start date of October 2019, approximately 3 years following final investment

decision • An updated simulation model reflecting these changes.

This has led to minor revisions in the production profiles, and reserves/resources estimates. These changes are highlighted in the appropriate sections. For completeness, data on fluid properties and the historic well testing are included even though they are unchanged from the previous evaluation.

8.1. PVT Data

No new PVT data has been received in 2015.

Xcite has taken samples from the 9/03b-6Z & 9/03b-7 wells, which have been analysed by OilPhase, Corelabs and OCTL. Historically, most samples appear to have been de-gassed to some extent, and this has impacted the results seen in the laboratory. During the EWT, the measured GOR over the first month, prior to any gas breakthrough, was an average 87 scf/stb (see Figure 8-2) at the separator. Three oil samples were taken from the separator to the laboratory for analysis, and found to still contain some 19-37 scf/stb. Therefore the total GOR has been assumed to be in the range 87-110-130 scf/stb.

The samples were re-saturated in the laboratory to the range in GOR’s above, and the bubble point pressure was measured, and is summarised below. Initial pressure is 1660 psia (at 3729 ftTVDss) making the Bentley crude undersaturated at initial reservoir conditions.

In the OilPhase tests, the samples were re-saturated to a GOR of 110 scf/stb and the viscosity was measured at various pressures, and found to be 1518 cP at initial reservoir pressure. Noting the range in GORs, above, the down- and high- side viscosities were estimated to be 1957 and 1311 cP respectively, from correlations, and this range was carried forward into the sensitivities investigated by the simulation modelling.

[References: ‘Fluid Summary, Bentley field’, Xcite, March 2013, ‘Bentley Heavy Oil PVT Study, Oilphase/Schlumberger, January 2013]

Low side Base High side

GOR (scf/stb) 87 110 130

Bubble point pressure (psia) 1000 1260 1490

Viscosity (cP 1957 1518 1311

Table 8-1 GOR and bubble point pressure summary

8.2. Well Test Operations Summary 2012

No new Well Test data was received in 2015.



During 2012, Xcite carried out an extended well test on two horizontal laterals; B6 (9/03b-7) and B5 (9/03b-7Z) for a total of 68 days. The completion allowed selective production from either or both laterals, but for most of the test period, production was from the B6 lateral alone. Production rates for the two laterals are shown in Figure 8-1 to Figure 8-2.

Figure 8-1 Production history from B6 lateral showing water cut

Figure 8-2 Production history from B6 lateral showing GOR



Figure 8-3 Late production history from B6/B5 laterals

The EWT was successful in many key objectives:

• Commercial flow was achieved from both laterals. A rate of up to 3400 bpd was taken from the B6 lateral and 2800 bpd from the B5 lateral. A total of approximately 150,000 stb was produced over a period of 68 days. The B5 lateral was on production for only 2 days, prior to termination of the test once the main objectives were satisfied. This is similar to rates achieved from 9/03b-6Z well test conducted in December 2010.

• The completion consisted of sand screens in both laterals, selective downhole valves to allow production from either or both laterals and dual ESPs. Although complex, the completion worked correctly and flow was achieved from both laterals, individually and together. Development wells are intended to have similar completions.

• No sand production was reported. • The duration of the test was intended to be sufficiently long in order to allow

measurable water production and thus to calibrate parameters within the simulation model. Water broke through after 5 weeks and the water cut reached 20% in the B6 lateral by the end of the test. The B6 horizontal lateral was drilled slightly deeper than is intended for future development wells in order to encourage earlier water breakthrough.

• The water production was lower than expected. • Pressure Build Up (“PBU”) data was collected to enable well test interpretation of

skin, kh and potentially other reservoir parameters (see Section 8.3 below) • It was not an objective of the test to investigate minimum connected volumes or

PIIP. One unanticipated result from the EWT was the temporary increase in GOR during production from the B6 lateral (see Figure 8-2). The increase and subsequent decrease in the GOR does not seem to be consistent with an oil field producing at or below its bubble point. Instead, it is thought more likely that the production extended to a minor gas pocket of biodegraded gas which was not dissolved in the oil. Given a solution GOR of ~90 scf/stb, the test produced an estimated 13.2 MMscf more than would be expected from solution gas alone. Fluid substitution tests based on Gasmann calculations indicate that any gas cap would have to be more than 5 ft in order for it to be seen on the seismic. Assuming that this gas pocket is less than 20 MMscf in volume then the maximum areal extent is thought to be of the region of 300 x 500 ft. It is possible that other localised gas pockets exist around the



core area of the field, in addition to the seismically observed gas caps in the South Eastern area of the field.

After approximately four weeks of high GOR production, the GOR seemed to return to solution gas levels. As there was no fundamental change in offtake rate, gas coning is not thought to have been an issue here. Therefore, any such impact of such gas pockets on ultimate recovery is felt to be minor. Furthermore, should 50 such pockets exist in Bentley field (outside the Bentley East area), each with 20 MMscf of gas, then the additional Gas Initially In Place (“GIIP”) would be around 1 BCF, which is also minor. This may benefit the development as a modest contribution to fuel gas.

Further details of the well test were available from the ‘Bentley Extended Well Test Report’, December 2012, written by Xcite.

8.3. Well Test Interpretation Summary

No new Interpretation data has been received in 2015.

During the B6 EWT production, a number of shut-ins occurred which enabled the pressure data recorded from the ESP downhole gauges to be used for PBU analysis. A summary of the PBU dates and durations is given in Table 8-2. PBU 1 and PBUs 3-5 on B6 gave very similar results, due to the durations, although the data quality was better in some than others due to the notice given prior to shut in. PBU 2 had the longest period of shut (some 81 hours) and gave insight into the more distant reservoir effects. Unfortunately the early data (first 40 mins) was lost as the shut in was unplanned, but the early response seems consistent with the data from the other tests.

Xcite provided two interpretation reports from Pearce Energy Consultants Ltd (“PECL”) and Schlumberger, both completed in early 2013, which came to similar conclusions.

Well/ Lateral

Period From: To: Hours

B6 PBU1 11 July 2012 10:26:00 12 July 2012 16:50 30

PBU2 23 July 2012 8:12:40 26 July 2012 17:27:00 81

PBU3 13 August 2012 6:44:40 13 August 2012 15:16:00 8

PBU4 30 August 2012 7:23:44 30 August 2012 18:30 11

PBU5 4 September 2012 8:00:23 5 September 2012 19:30 36

B5 PBU1 13 September 2012 19:59:23 15 September 2012 12:00:00 40

Table 8-2 Summary of PBU dates and durations

All of the PBUs seem to indicate two periods of radial flow: the first seen with dt<5 hrs (log10(dt) < 0.5), and the second with dt>10 hrs, (log10(dt) > 1). The first period is consistent with radial flow of the horizontal lateral within the oil leg, the second period is consistent with radial flow within the aquifer, with the well acting as effectively a single point, compared to the radius of investigation. These periods are visible in the two derivative plots in Figure 8-4. A horizontal trend line can be drawn through either flat section of the data and its vertical position has an inverse relationship with k.h/µ, where k is



the permeability, h is either the length of the horizontal lateral or the thickness of the aquifer, depending on the case, and µ is the viscosity of the fluid, either oil or water.

An inherent point of well test interpretation is that permeability is not measured directly, but requires that the viscosity and the flow regime are known and understood.

The two radial flow periods indicate two values of k.h/µ, with the second value being around an order of magnitude better than the first (the vertical value of the two lines goes from around 9 to 1 on the scale on the derivative plots).

The first radial flow period is thought to be the radial flow around the horizontal lateral in the oil leg. Using the value of oil viscosity of 1518 cP (see Section 8.1) and a producing lateral length of 2049ft gave a value of k of 47,000 mD. For a horizontal lateral this is thought likely to be equivalent to √(kh.kv).

The second radial flow period suggests a k.h/µ which is nearly ten times better than the first. It is not feasible that this is due to an improvement in permeability in the oil leg. The deviation away from the first radial flow period is around 1 hour, which is approximately 100ft from the well, and coincident with the distances to both the roof of the reservoir and the OWC. Therefore, this second radial flow period is indicative of the water leg, and as no boundary is seen to 81 hours, which would be around 5000ft from the wellbore, the radial flow regime would appear to be a horizontal distance from the well in the water leg. The vertical thickness of the aquifer is around 200ft and the water viscosity is 0.74 cP, which gives a value of kh of around 500 mD.

Figure 8-4 Derivative plots for PBU 1 & PBU 2

The permeability of the oil leg is very high with the estimation of 47,000 mD. By analogue, the nearby heavy oil fields Mariner and Bressay are understood to have permeabilities of up to 50,000 mD (source: informal communication with the fields’ operator, Statoil). If the permeability was less, then the viscosity would also have to be less, and this is inconsistent with the measurements from the fluid samples. The use of this high value of permeability and viscosity in the oil leg leads to a conservative estimate of recovery in the simulation results, as water would more rapidly breakthrough.

The second unusual result is that the permeability in the aquifer at between 500mD and 2000mD is approximately two orders of magnitude smaller than that in the oil leg. This is thought to be due to partial cementation of the sands in the water leg. There is evidence for a reduction in permeability in the water leg from:

• Rate of penetration while drilling in the oil leg relative to the water leg



• The degree of washout in the oil leg relative to the water leg • The core permeability measurements on core recovered in 9/3-3 in its water leg.

Xcite provided data acquired while drilling the 9/03b-6 well, showing the Rate of Penetration (“ROP”) vs. the Weight on Bit (“WOB”) (Figure 8-5). The data clearly shows that much less weight was required to drill through the oil leg than the water leg, and that the average rate of penetration was higher, indicating that the rock below the OWC is harder (and hence possibly lower permeability) than above it. As this data was acquired within the same well, potential reasons such as a different rig and drilling mud can be eliminated as potential causes. Verbal communications with Chevron, the operator of the Captain field where permeabilities are understood to be in the range of 5,000-7,000 mD indicate that ROPs achieved there are around 50 ft/hr, much lower than in Bentley, suggesting that the Captain rock is harder, and lower permeability.

Figure 8-5 ROP vs. WOB drilling data from the 9/03b-6 well

Washouts can be an indication of the hardness, and hence permeability of the rock. Data from three Bentley area wells are shown in Figure 8-6, with the OWC indicated. The Caliper log is shown in purple, and is in gauge in the water leg, mainly in the 9/3-2A and 9/3-4 wells, but is out of gauge in the overlying sands in the oil leg.



Figure 8-6 Caliper logs in various Bentley area wells

Some core data is available for the 9/3-3 well, which was water bearing. The fact that any core was recoverable, and did not disintegrate into a pile of sand, unlike other coring attempts, suggest that the rock intersected was harder than the oil bearing sands. The conventional core analysis results indicated permeabilities in the range of 700-1700mD, although this was in core with slightly higher gamma ray readings.

Individually, none of these three indicators are a guarantee of permeability, but collectively, they do seem to confirm the picture seen from the well test interpretation about the contrast in permeability from the oil to the water leg.



8.4. Simulation Model

8.4.1. General Description

The static model was incorporated into an updated simulation model in 2014, and this was unchanged in 2015. This model is a full field model, which is an improvement on the sector model available in previous years’ evaluations and has been created in Roxar’s Tempest simulation software. The model has 40 x 40m areal spacing, in a model with 168 x 462 x 44 grid cells, or ~3.4 million cells in total. The model was history matched against the available EWT data and used for full field prediction.

Forecasts were based on 21 oil producers in the First Phase Development (FPD) area and 14 oil producers in the Second Phase Development (SPD), each with up to 4 laterals. The gas caps in Bentley East were accessed by one (near) vertical well within the SPD, and both FPD and SPD had 3 water injectors each, giving 6 water injectors in total. The total well count was 42. The purpose of the water injectors is chiefly for produced water disposal.

The location of the wells is shown in Figure 8-7 and Figure 8-8.



Figure 8-7 Location of FPD Wells



Figure 8-8 Location of SPD Wells

ESPs have been assumed for each of the producers. Maximum offtake rates of up to 11,500 bopd and 23,000 blpd were assumed, per well, for the P50 case. The higher liquid offtake rate is due to the much higher viscosity of the oil, compared to water (1518 cP vs 0.74 cP). For the low and high cases, these offtake rates were adjusted by -20% and +20%, respectively.

The full field development facilities constraints are unchanged since 2014, and are shown below:



RAR 2013 RAR 2014 and 2015

Oil

(Mbpd)

Water

(Mbpd)

Liquid

(Mbpd)

Oil

(Mbpd)

Water

(Mbpd)

Liquid

(Mbpd)

Phase 1 45 183 185 45 265 270

Phase 1 + 2 70 380 385 90 530 540

Table 8-3 Full field liquid handling limits

First oil date was assumed to be 1st October 2019. Total effective uptime has been estimated at 96% for the first five years, and 92.7% thereafter. These estimates include the impact of both planned and unplanned downtime (wells and facilities).

Due to the large size of the model, and the slow runtimes, Xcite ran the model with the FPD well area separately from the SPD area. Due to the predominantly vertical movement of fluids in the reservoir from the underlying water leg up to the horizontal laterals, and the separation between the two areas, these combined results will not have been significantly affected by the separation of the runs.

The model, as utilised, has been carefully reviewed by AGR TRACS and is considered reasonable and within common industry practice.

8.4.2. Reference Case results

The results from the reference case models ran by Xcite were over the full field area, and the recovery to 35 years was used as a reference. Constraints per well, and for the facilities were applied as noted above.

The current drilling schedule for the life of field (LoF) production wells was updated in 2015 and is shown in Table 8-4. The sequence of wells may change, and is subject to rig availability, as is common with most projects.



Well On Stream (1) Platform FPD W1 01/11/2022 FPD FPD W2 01/12/2019 FPD FPD W3 01/07/2020 FPD FPD W4 01/10/2019 FPD FPD W5 01/04/2021 FPD FPD W6 01/01/2025 FPD FPD W7 01/03/2020 FPD FPD W8 01/06/2021 FPD FPD W9 01/01/2022 FPD FPD W10 01/01/2021 FPD FPD W11 01/02/2023 FPD FPD W12 01/08/2022 FPD FPD W13 01/05/2023 FPD FPD W14 01/04/2022 FPD FPD W15 01/10/2020 FPD FPD W16 01/05/2020 FPD FPD W17 01/08/2021 FPD FPD W18 01/04/2025 FPD FPD W19 01/04/2026 FPD FPD W20 01/08/2025 FPD FPD W21 01/11/2025 FPD SPD W1 01/12/2026 SPD SPD W2 01/04/2028 SPD SPD W3 01/06/2027 SPD SPD W4 01/12/2025 SPD SPD W5 01/07/2026 SPD SPD W6 01/01/2028 SPD SPD W7 01/07/2028 SPD SPD W8 01/10/2024 SPD SPD W9 01/05/2025 SPD SPD W10 01/01/2025 SPD SPD W11 01/09/2025 SPD SPD W12 01/03/2027 SPD SPD W13 01/10/2027 SPD SPD W14 01/04/2026 SPD SPD GP 01/01/2041 SPD

Table 8-4 Life of field drilling schedule, production wells (1) On stream dates reported here are rounded to the first day of the month following the month the well is on stream

Each of the wells is fitted with an ESP to enable the fluids to be lifted to surface. Each of the first ten FPD production wells is intended to start production with two laterals on stream. Then, after a period of ~4 years, when the water cut has developed, the next two laterals are drilled, and put on to production, with the first two laterals shut in via ICVs in the completion. Then, after another ~3 years, all four laterals are put on line for the rest of the field life. This process is intended to maximise initial dry/drier oil production in the early years. Having established learnings from the first ten wells, it is intended that the remaining 11 FPD production wells and all SPD production wells will be drilled as quad laterals.

Sensitivities at different liquid offtake rates indicated virtually identical relationships of cumulative oil vs water cut.



Work on the GRV suggested that there may be considerable variation in PIIP at the flanks of the field in the thinner, undeveloped oil columns. In order to avoid this adversely impacting recoverable volumes in the Monte Carlo simulation, the PIIP within the thickest oil columns (60’ or more) were calculated.

Figure 8-9 Profiles from FPD reference case run

Figure 8-10 Profiles from reference case SPD Run



The reference models were then used to estimate nominal recovery factors for both the total PIIP and the developable PIIP (i.e. PIIP with at least 60’ of oil column thickness accessed by development wells). The reference models were run as standalone cases. The results are summarised below. In practice, the FPD and SPD components of the field development plan have shared facilities capacity. Under full field development conditions, FPD production is uplifted by the utilization of SPD capacity. This arises from the selection of producing wells to maximise oil production in the context of constraints in total facilities capacity (see section 8.6). There are some minor differences in PIIP between the simulation model and the Petrel model, mostly due to the nominal value of 1.06 rb/stb for the FVF used in the Petrel model, rather than the more correct 1.043 used in the simulation model.

PIIP MMstb Recovery MMstb (1)

Recovery Factor %

PIIP within 3670 contour

MMstb

Recovery Factor %

FPD 578.7 209.6 36.2% 428.1 49.0%

SPD South 328.4

41.74 21.9%

84.3 49.5%

SPD East 30.22 109.2 27.7%

Total 907.1 281.56 31.0% 621.6 45.3%

Table 8-5 Summary of Recovery from Reference Simulation models (1) Based on 35 years production

The results indicate a consistency between the FPD and SPD South recovery factor within the 60+’ oil column of 49-49.5%, and that the equivalent RF for the SPD East area is much lower, 27.7%.

A number of sensitivities were performed on these models to understand the impact on this nominal recovery factor, so that a Monte Carlo approach could be used to give a range in Estimated Ultimate Recovery (“EUR”).

8.5. Impact on the Range in Recovery Factor

Various adjustments were made to the results from the sector model before the recovery factor was applied to the LoF development plan. Each has been assessed relative to the recovery factor from the reference model.

8.5.1. Field Life

The nominal field life of the Phase 1 and 2 facilities is to be 35 years – until end 2054.

8.5.2. Impact of Permeability Uncertainty within the Oil Leg

Based on the well test data, the typical value of permeability in the oil leg was estimated to be 47 Darcies. Sensitivities were performed by varying the average to 30 and 60 Darcies, to reflect uncertainty away from the well test control. The impact on the recovery is summarised below:



Value (Darcies) Impact on Recovery

Sensitivity Low Med High Low Med High

Permeability Oil leg 30 47 60 88.7% 100% 104.8%

Table 8-6 Impact from sensitivities on permeability in the oil leg

8.5.3. Impact of Permeability Uncertainty within the Water Leg

Due to diagenesis, the permeability of the rock in the aquifer is significantly less than that in the oil leg, and this was demonstrated by the well test analysis, drilling RoP, degree of washout and core permeability measurements.

Xcite have used a value of 1500 mD in their model, although the well test interpretation suggest that a lower value of 500 mD may exist, which presents an upside as it reduces the speed of water breakthrough. A downside of 2000 mD was also considered and gave a modest impact on recovery:

Value (mD) Impact on Recovery


Permeability Water leg 2000 1500 500 99.1% 100% 100.8%

Table 8-7 Impact from sensitivities on permeability in the water leg

8.5.4. Impact of Kv/Kh ratio

Well test interpretation showed an average Kv/Kh of 0.6. This value was used in the original homogeneous permeability model. In reality, there is little evidence for any shale barriers/baffles within the reservoir and no vertical baffles were seen on the well tests. The new model has heterogeneous permeability so the Kv/Kh has been raised to 0.7 for the base case with an overall range in the Kv/Kh ratio of 0.5 to 0.9. This has a limited impact on water movement.

The impact on recovery is shown below:

Value Impact on Recovery


kv/kh 0.9 0.7 0.5 97.4% 100% 101.4%

Table 8-8 Impact from sensitivities on kv/kh

8.5.5. Impact of Relative Permeability Curves

The relative permeability curves used in the Xcite reference case were derived from history matching the EWT data, where water breakthrough was achieved, and reached 20% by the end of the three month test. Therefore, the part of the relative permeability curves at lower water saturations seem calibrated with this data. A range of relative permeabilities were considered based on analogue data, as shown in Figure 8-11. Residual oil saturation was considered separately (see next section).



Figure 8-11 Relative permeability curve sensitivities

The range in outcomes is shown below:

Value Impact on recovery


Relative Permeability Down side

Base case

Up side

87.4% 100% 107.0%

Table 8-9 Impact from sensitivities on relative permeability

8.5.6. Impact of Residual Oil Saturation

A residual oil saturation (Sorw) of 15% was assumed in the reference case, and was used within the history matched model of the well test. However, as the test only achieved 20% water cut, the actual value of Sorw is not confirmed through the history match. A range of values from 5 to 25% was assumed to test the model’s sensitivity to Sorw. The range in outcomes is shown below:

Value Impact on recovery


Residual So 25% 15% 5% 93.2% 100% 104.7%

Table 8-10 Impact from sensitivities on residual oil saturation



8.5.7. Impact of Initial Water Saturation

The water saturation in the reference model was based on the logged water saturation and a saturation height function was derived to match this. Two sensitivities were considered to create an up- and down-side which are shown in Figure 8-12. These were loaded into the simulation model and run to investigate the impact on recovery factor. It must be noted that these also had an impact on PIIP, and so the impact on recovery factors is shown in Table 8-11. The impact on recovery factor is minor.

Figure 8-12 Saturation/Height function sensitivities

Value Impact on Recovery Factor


Water Saturation Down side

Base case

Up side

98.8% 100% 100.9%

Table 8-11 Impact from sensitivities on water saturation



8.5.8. Impact of Oil Viscosity

The range of oil viscosity was discussed in section 8.1. The impact of varying the viscosity from 1311 to 1957 cP on recovery is shown below:

Value (cP) Impact on Recovery


Oil viscosity 1957 1518 1311 91.2% 100% 104.5%

Table 8-12 Impact from sensitivities on oil viscosity

8.5.9. Impact of Rock Compressibility

The formation rock compressibility was assumed to be 3*10-6 psi-1 in the reference case. This was varied up to 20*10-6 psi-1. A downside was not considered as the base value was believed to be already a low estimate for such friable rock. The recovery is not very sensitive to rock compressibility due to the pressure maintenance from water injection. The impact is shown below:

Value (psi-1) Impact on Recovery


Rock Compressibility 3*10-6 3*10-6 20*10-6 100.0% 100% 100.4%

Table 8-13 Impact from sensitivities on rock compressibility

8.5.10. Basis for Range in Recoverable Volumes

The ranges in PIIP and developable PIIP were presented in Table 7-2. The nominal recovery factors for the FPD, SPD South and SPD East areas were presented in Table 8-5. These nominal recoverable factors were modified within a Monte Carlo simulation by the impacts shown in Table 8-6 to Table 8-13. The result was a range in recoverable volumes for the first 35 years. Comparing these values with the PIIP range in Table 7-2 gives the recoverable volumes shown in Table 8-14, and the recovery factors shown in Table 8-15.

Area P90 P50 P10

FPD 149.4 167.6 182.8

SPD South 37.2 42.3 47.1

SPD East 13.1 25.3 47.3

Total (Probabilistic) 200.8 235.4 274.2

Table 8-14 Range of recoverable volumes from Monte Carlo Simulation, MMstb



Bentley Recovery Factors P90 P50 P10

Bentley FPD Oil 33.4% 31.9% 30.1%

Bentley SPD South Oil 25.5% 24.6% 23.6%

Bentley SPD East Oil 11.7% 15.1% 18.8%

Bentley FPD Developable Oil 48.3% 46.2% 43.8%

Bentley SPD South Developable Oil 48.9% 46.7% 44.1%

Bentley SPD East Developable Oil 25.6% 25.7% 26.0%

Bentley Total 27.1% 26.7% 26.5%

Table 8-15 Recovery Factors from Monte Carlo Simulation

8.6. Profiles

Production Profiles were based on the results of the simulation model and the Monte Carlo process. Fractional flow curves for each well in the simulation model were generated. The recovery to 35 years from the Monte Carlo results were used to scale the fractional flow curves.

Production profiles were produced for the low, mid and high results, using the well phasing in Table 8-4, and the facility and well offtake rates in Section 8.4.1. The facility limits, especially on total liquid capacity, were applied to all cases, which allowed wells to be produced more aggressively in the P90 case, and constrained some of the upside of the P10 case, while still honouring the available production capacities. The results therefore differ from the results of the pure Monte Carlo simulation. The cumulative volumes are shown in Table 8-16 and the profiles are shown in Figure 8-13. The comparison between the Monte Carlo results and the constrained profiles (Table 8-16) shows the uplift from flowing the cases at an increased liquid offtake rate, compared to the reference simulations, which were run on a standalone basis with no uplift from shared facilities, and from choking back wells with higher water cut which was not done effectively in the simulations.

Total Recoverable (MMstb) P90 P50 P10

From Monte Carlo 200.8 235.4 274.2

From Profile to end 2054 233.9 265.3 295.8

From Profile to end 2069 246.8 285.8 324.9

Table 8-16 Recoverable volumes from Monte Carlo Simulation and Profiles

At this stage, no additional volumes have been estimated for potential EOR schemes. Xcite are planning additional studies to investigate the potential of polymer injection based EOR schemes, and additional Contingent Resources for EOR may be included in a future review, prior to a pilot scheme to validate the studies.



Figure 8-13 P90, P50, P10 oil profiles – barrels oil per day



Date Oil rate Water rate

Gas rate Date Oil rate Water rate

Gas rate

bpd bpd MMscfd bpd bpd MMscfd 2019 2,542 1,525 0.22 2055 3,919 514,100 0.37 2020 23,214 52,649 2.02 2056 3,669 514,100 0.34 2021 30,904 154,380 2.69 2057 3,411 514,100 0.30 2022 40,976 205,629 3.56 2058 3,155 514,100 0.28 2023 40,122 197,570 3.49 2059 2,915 514,100 0.26 2024 36,347 278,933 3.88 2060 2,695 514,100 0.24 2025 58,395 342,816 6.17 2061 2,485 514,100 0.22 2026 51,670 395,400 5.69 2062 2,284 514,100 0.20 2027 41,987 470,544 4.66 2063 2,099 514,100 0.19 2028 33,842 477,861 3.34 2064 1,930 514,100 0.17 2029 28,420 486,868 2.77 2065 1,776 514,100 0.17 2030 23,643 493,932 2.32 2066 1,634 514,100 0.15 2031 20,300 497,836 2.03 2067 1,505 514,100 0.14 2032 18,132 500,209 1.81 2068 1,387 514,100 0.13 2033 16,556 502,146 1.66 2069 1,278 514,100 0.12 2034 15,219 503,811 1.55 Total MMstb MMstb BCF 2035 13,980 505,247 1.43 (2055-

2069) 13.2 2,816.8 1.2

2036 12,978 506,479 1.30 2037 12,120 507,550 1.22 2038 11,385 508,506 1.11 2039 10,721 509,327 1.02 2040 10,100 510,069 0.96 2041 9,569 510,726 2.09 2042 9,070 511,313 2.04 2043 8,519 511,851 1.99 2044 7,986 512,332 1.94 2045 7,510 512,804 1.90 2046 7,074 513,309 0.94 2047 6,642 513,724 0.61 2048 6,192 514,048 0.57 2049 5,800 514,100 0.54 2050 5,422 514,100 0.50 2051 5,073 514,100 0.47 2052 4,756 514,100 0.45 2053 4,470 514,100 0.42 2054 4,187 514,100 0.40 Total MMstb MMstb BCF Total MMstb MMstb BCF

(to end 2054)

235.9 5,812.8 25.5 (to end 2069)

249.1 8,629.5 26.7

Table 8-17 P90 average profiles





Gas rate


2069) 20.9 2,816.8 2.4


(to end 2054)

267.3 5,801.1 39.9 (to end 2069)

288.2 8,617.8 42.3






Gas rate


2069) 29.5 2,816.8 4.0


(to end 2054)

298.0 5,768.7 54.9 (to end 2069)

327.5 8,585.4 58.9




9. Prospects, Blocks 9/4a, 9/8b, 9/9h

Prospects in blocks 9/4a, 9/8b & 9/9h target the Lower Palaeocene sands of the Maureen Formation (Figure 9-1). This is located at a deeper stratigraphic level than the Dornoch Formation. These sands are present in all the nearby wells where they contain water. Top seal is provided by the overlying shales of the Lista Formation. Currently four prospects, Clement, Chadwick, Cartwright and Camm have been delineated.

Figure 9-1 Top Lower Palaeocene sandstone depth map



9.1. Clement

The Clement Prospect is located 3.5km northeast of Bentley on a fault terrace on the edge of the Viking Graben. It consists of a closure of Lower Palaeocene Sandstone pinching-out up-dip against basement in an up-thrown fault block (Figure 9-2).

Figure 9-2 Line 25740 through Clement

Closure along strike is produced by rollover and the top seal by the Lista Shale. The crest has been mapped at a depth of -1760m TVDSS and the spill point is to the south at -1889m TVDSS. The prospect is mapped at the northern edge of the available 3D data which may restrict the total size of the trap which currently covers an area of 1.1km2 (Figure 9-3).



Figure 9-3 Top Lower Palaeocene Sandstone Depth Map, Clement

Contact of the reservoir with a subsidiary fault to the east was used to define the P90 GRV. The P10 case GRV was defined by the maximum polygon area and a contact 5m below the spill point recognising uncertainty in depth conversion. A log normal assumption was used to give the range of GRV. This is given in Table 9-1 and PIIP and prospective oil resource are given in Table 9-2 below.

Upper OWC

TVDSS m

Lower OWC

TVDSS m

P90 GRV

m3*106

P10 GRV

m3*106

-1820 -1894 3.67 39.69

Table 9-1 Clement gross rock volume inputs



Clement Mean P90 P50 P10

PIIP Oil (MMstb) 13.3 2.8 9.1 29.0

Prospective oil resource (MMstb) 4.7 0.9 3.1 10.2

Table 9-2 Clement PIIP and prospective resources

The Clement prospect is given a moderately good POS. The main risk is the presence of an effective seal at the pinch-out of the reservoir against basement to the west. The hydrocarbon charge risk is due to the unproven presence of a migration pathway through the system.

Source Reservoir Seal Trap Overall

0.70 0.85 0.40 0.90 0.21

Table 9-3 Clement probability of success

9.2. Chadwick

The Chadwick Prospect is located 4km east of Bentley on a fault terrace on the edge of the Viking Graben. It consists of a closure of Lower Palaeocene Sandstone pinching-out against basement in an up-thrown fault block (Figure 9-4).

Figure 9-4 Line 25450 through Chadwick

Closure along strike is produced by rollover and the top seal by the Lista Shale (Figure 9-5). The crest has been mapped at a depth of -1750m TVDSS and the spill point is to the south at -1899m TVDSS.



Figure 9-5 Top Lower Palaeocene Sandstone Depth Map, Chadwick

There are two subsidiary closures present and the largest which forms the crest of the structure was used to define the P90 GRV. The P10 case GRV was defined by the maximum polygon area, 4.2km2, and a contact 5m below the spill point, recognising uncertainty in depth conversion. A log normal assumption was used to distribute the range of GRV given in Table 9-4 and PIIP and prospective oil resource forecast are given in Table 9-5.

Upper OWC

TVDSS m

Lower OWC

TVDSS m

P90 GRV

m3*106

P10 GRV

m3*106

-1860 -1924 42.57 213.66

Table 9-4 Chadwick gross rock volume inputs



Chadwick Mean P90 P50 P10

PIIP Oil (MMstb) 87.7 31.3 71.4 164.0


Table 9-5 Chadwick PIIP and prospective resources

The Chadwick prospect is given a moderately good POS. The main risk is the presence of an effective seal at the pinch-out of the reservoir against basement to the west. The hydrocarbon charge risk is due to the unproven presence of a migration pathway through the system.


0.70 0.85 0.40 0.90 0.21

Table 9-6 Chadwick probability of success

9.3. Cartwright

The Cartwright Prospect is located 4.2km southeast of Bentley on a fault terrace on the edge of the Viking Graben (Figure 9-6). It consists of a closure of Lower Palaeocene Sandstone in a downthrown fault block juxtaposed with basement.

Figure 9-6 Line 24970 through Cartwright



Closure along strike is produced by rollover and the top seal by the Lista Shale. The crest has been mapped on a subsidiary fault block at a depth of -1760m TVDSS and the spill point is to the south at -1870m TVDSS (Figure 9-7).

Figure 9-7 Top Lower Palaeocene Sandstone Depth Map, Cartwright

There are a number of subsidiary closures present and the fault block which forms the crest was used to define the P90 GRV. The P10 case GRV was defined by the maximum polygon area, 4.0km2, and a contact 5m below the spill point. A log normal assumption was used to distribute the range of GRV. The GRV inputs are given in Table 9-7 and PIIP and prospective oil resource in Table 9-8 overleaf.



Upper OWC

TVDSS m

Lower OWC

TVDSS m

P90 GRV

m3*106

P10 GRV

m3*106

-1840 -1875 35.59 120.26

Table 9-7 Cartwright gross rock volume inputs

Cartwright Mean P90 P50 P10

PIIP Oil (MMstb) 55.1 25.8 48.8 92.1


Table 9-8 Cartwright PIIP and prospective resources

The Cartwright prospect is given a lower POS than the prospects above due to the additional faults present, especially the late moving bounding fault to the west. This is expected to result in significant chance of leakage from the crest of the trap.


0.70 0.85 0.30 0.90 0.16

Table 9-9 Cartwright probability of success

9.4. Camm Prospect

The Camm Prospect is located 3km south of Bentley and 4km northeast from the Bruce Field. It consists of a closure of Lower Palaeocene Sandstone in a downthrown fault block juxtaposed with basement (Figure 9-8).



Figure 9-8 Line 3880 through Camm

Closure along strike is produced by rollover and the top seal by the Lista Shale. The crest has been mapped at a depth of -1590m TVDSS and the spill point at -1675m TVDSS (Figure 9-9).

Figure 9-9 Top Lower Palaeocene Sandstone Depth Map, Camm

There are a number of subsidiary closures present and the largest, which covers an area of 0.75km2, was used to define the P90 GRV. The P10 case GRV covers an area of 4.5km2 using an OWC 5m below the spill point. A log normal assumption was used to give the range of GRV. Input GRV parameters are given in Table 9-10 and PIIP and prospective oil resource in Table 9-11.



Upper OWC

TVDSS m

Lower OWC

TVDSS m

P90 GRV

m3*106

P10 GRV

m3*106

-1640 -1680 10.10 129.92

Table 9-10 Camm gross rock volume inputs

Camm Mean P90 P50 P10

PIIP Oil (MMstb) 42.8 7.5 27.2 97.7


Table 9-11 Camm PIIP and prospective resources

The Camm prospect is given a moderate POS due to the late fault movements within the trap, especially on the bounding fault to the north. This is expected to result in significant chance of leakage from the crest of the trap. However, reservoir quality seen in nearby wells has better properties than wells further to the east.


0.70 0.95 0.30 0.90 0.18

Table 9-12 Camm probability of success



10. Development Plan

The Bentley field in the 9/3b Block of the Northern Sector of the UKNS is proven by eight reservoir penetrations with the most recent wells, 9/03b-5, 9/03b-6 & 6Z and 9/03b-7 & 7Z drilled by Xcite. The Bentley field crude is low gravity (density 0.997 @15.6o C), high viscosity and high TAN (Total Acid Number, in this case predominantly naphthenic acids). However, it has low sulphur, low metals, no wax and a high yield of vacuum gas oil for refinery upgrading operations.

Fraction Yield % wt

Yield % mole

Yield % volume

Mol. Weight

Density @ 15.6°C

IBP - 150 °C 0.00 0.00 0.00 - -

150 - 230 °C 1.06 2.84 1.21 156.3 0.8745

230 - 350 °C 15.62 27.78 16.96 235.4 0.9171

350 - 375 °C 5.67 7.94 5.87 298.9 0.9613

375 - 550 °C 41.03 47.80 41.74 359.3 0.9785

550+ residue 36.62 13.64 34.22 1123.8 1.0652

API Gravity 10 - 12

Sulphur mol% 0.87

Viscosity @50o C 2350 cst

Viscosity @80o C 225 cst

TAN mgKOH/g 5.5 – 8.5

Pourpoint oC 12 - 18

Table 10-1 Bentley whole crude yield and summary properties

Development is planned around two phases:

10.1. First Phase Development (FPD)

Phase 1 consists of a 24-slot mobile offshore production unit (MOPU) bridge linked to a floating storage and offloading vessel (FSO) housing the living quarters and helideck. Well stock consists of 21 producers and 3 water injection wells.



Figure 10-1 Bentley Phase 1 MOPU and FSO on location

The MOPU separation system for degassing and bulk dewatering is designed to process up to 45 Mbo/day and 265 Mbw/day (gross liquids 270 Mb/d). For flow assurance purposes, only partial de-watering will take place on the platform with the balance of fluids (minimum of 30% by volume watercut) transferred via jumper hoses to reception tanks on the purpose built cylindrical FSO. Diluent is added in the reception tanks to aid separation and to reduce the viscosity of dry crude to a 450-600 cP range (at 40 degrees centigrade). Diluent dosing to achieve this is expected to be in the range of 20-25%.

The balance of water separation will occur in settling tanks in the FSO from where produced water is returned to the MOPU for re-injection. A spare transfer line, with the option to use for diluent, is included in the facilities statement of requirement (SoR). The transfer line runs between the FSO and MOPU and may be used to aid the separation process and as back-up flow assurance. The MOPU will also host utilities, including power generation, for the support of production operations, with field operations controlled from the FSO.

The FSO will have total storage capacity of approximately 1 MMbbls with allocation in net capacity as follows:

• Reception tanks: 100 Mbbls • Diluent storage: 150 Mbbls • Crude storage capacity for export operations: 600 Mbbls, including diluent dosage • Produced water storage: 75 Mbbls • Slops and bottoms: 44 Mbbls

Tanks dedicated to crude export will be coil-heated to reduce viscosity. Evacuation will be by shuttle tanker under an offtake and marketing agreement with BP Oil International Limited. Under this agreement, BP will supply diluent (light crude, condensate etc.) to ensure delivered crude is compatible with receiving terminal requirements.

In the First Phase drilling program, the first 10 production wells will initially be completed as lower dual lateral wells before 2 new laterals (upper completions) are added. The remaining 11 production wells of the FPD will be completed at the outset with 4 lateral sections (“Quads”). Phase 1 includes 3 water injection wells. All wells whether of standard or extended length will be constructed using full hole well architecture. This replaces the previous slim hole design. All oil producers are supported by artificial lift (electro submersible pumps, “ESPs”) with a typical time to failure of between 2.5 and 4 years depending whether a single or double pump arrangement is used. All wells are planned with double pumps in their early life to maximise uptime.



The close spacing of laterals counters the limited mobility under reservoir conditions of viscous heavy oil and the multiple lateral sections provide a large surface area for even drawdown and reduced risk of early water coning. The Bentley development will be short of fuel gas for meeting its power generation and process heat requirements and the Phase 1 development will include the installation in 2021 of a fuel gas import line tied in to existing infrastructure.

Phase 1 utilizes 24 drill over slots and consists of 21 production wells plus 3 water injection wells as shown in Figure 10-2.

Figure 10-2 Bentley FPD well locations



10.2. Second Phase Development (SPD)

The SPD, which is planned to begin 5 years after FPD drilling starts, will comprise a normally unmanned fixed platform structure, controlled from the FSO unit/MOPU, located approximately 6.5 km to the south-south west of the Phase 1 MOPU. Drilling for the SPD starts 5 years after the commencement of FPD drilling and will run for approximately 2 years in parallel with it and continue for a further 2.5 years. All Phase 2 wells will be drilled and completed as Quads at the outset

The production unit of the SPD will broadly follow the design and functionality of the FPD platform with planned crude oil processing capacity of 45 Mbopd and total liquids handling capacity of 270 Mblpd. On completion of the SPD, full field development (FFD) oil processing and liquids handling capacities will rise to 90 Mbopd and 540 Mblpd respectively. The 20 well slot configuration will have 14 slots allocated to oil production, 1 gas production slot for Bentley East and 3 for water injection.

Figure 10-3 Bentley SPD well locations



The first and second phase production hubs will operate as an integrated facility with both power and the production fluids exchangeable between the SPD and FPD facilities to allow capacity and fuel gas sharing between the hubs. The SPD will have its own dedicated oil line to the FSO.

Figure 10-4 Full field development production facilities schematic

10.3. First and Second Phase CAPEX schedule

Project sanction and FDP approval from the DECC is assumed to be in 2016, subject to financing arrangements being concluded, with the start of production planned for 4Q 2019, approximately 3 years following final investment decision. Project planning architecture is in place, procurement strategies have been defined and long lead items identified. The Bentley field development plan can be considered to have completed the Select Stage with some aspects, such as well engineering, at the Develop Phase.

Cost Item From Basis Comments

FPD MOPU (Mobile Offshore Production Unit)

Yard quote EPCIC Quote – substructure and topsides. Includes:

Engineering, Procurement, Fabrication, Load-out, transportation, Installation, Hook-up and Commissioning

Cost scaled up for 24 well slots from a 20 well quote. Costs scaled up for hook-up and commissioning based on AMEC Foster Wheeler and Arup guidance. All engineering by AMEC Foster Wheeler/Arup/Aibel. Contingency of 15% added by Xcite on items not included in lump sum quotes.



Cost Item From Basis Comments

FSO (floating storage and offtake vessel), cylindrical hull (1)

Yard quote Lump sum yard quotation for hull, all other costs estimated based on Xcite Statement of Requirement

Yard quotation includes basic engineering. Insurance costs added. Includes contingency of 10-20% on all items excluding hull costs (fixed price).

Well costs ADTI/Xcite/COSL Costs informed by prior wells 7, 7z and earlier, SPD Well Consultants and other analogues. Rig rate per quotes.

Detailed estimates to AFE level for near and far wells, cross referenced against time analysis of Rushmore database. 2% Waiting on weather, phased learning curve and 3% contingency on rig rate utilization.

Total 9% contingency.

Fluid Transfer and Mooring (2)

Yard quote Budget costs Includes 10% contingency

Gas Import Facilities

Genesis Genesis in-house estimate using cost estimating software CosMos and ADEPT

Assumes 10 km 6” pipeline from tie-in at Kraken field installed in 2021. Includes 20% contingency.

Table 10-2 Phase 1 CAPEX components and cost estimate basis (1) In the economic evaluation, FSO costs are converted to a lease which is then incorporated into OPEX (2) Costs are included as part of the FSO lease component

All CAPEX costs have been updated based on written and oral submission from vendors and other contractors. In addition, Xcite’s review of drilling and completion times referencing Rushmore’s North Sea drilling database resulted in a reduction of 250 days in estimated jack-up drilling time for the FPD and 56 days in well workover time.

The development plan for the Bentley Field entails CAPEX disbursements of $4.04 billion, including contingency rates as above and escalation of 2% p.a. (base year cost 2016). Development drilling CAPEX accounts for 71% of CAPEX disbursements during Phase 1 of the FDP and 66% over the life of the field. Full field economics incorporates the installation of Second Phase Development (“SPD”) facilities in 2024.

Included in the economics is the laying and tie-in of a 6 inch fuel gas import line to allow delivery of gas from existing nearby infrastructure. This is planned for commission two years after first oil. The Bentley development will be short of gas and this tie-in will supplement the limited associated gas and substitute more costly diesel.

CAPEX estimates were updated by Xcite at the end of 2015 and early 2016 to capture current costs, albeit in a market that is still adjusting to lower oil prices. The percentage reductions correspond with market changes observed elsewhere by AGR TRACS. The original estimates had been reviewed by AGR TRACS and were based on a mix of lump sum quotes, expressions of interest and engineering based cost estimating models.



FPD CAPEX Item % Change vs 2014 RAR Contingency (1)




Wells -23.0% 9%

Abex -0.1% 20%

Total -19.2%

Table 10-3 FPD cost changes (2015 RAR vs 2014 RAR, unescalated) (1) Applied to non-lump-sum costs

FPD Capitalised Lease Item % Change vs 2014 RAR

Contingency

Floating Storage and Offtake Vessel (converted to a lease and incorporated into OPEX)

+3.8% 11%

Table 10-4 2015 FPD capitalised lease revision

In parallel with the CAPEX review and update, OPEX costs were also updated resulting in OPEX costs being reduced by 11.2%. Key reductions are noted in well engineering, operations support services (supply boats, helicopter, communications etc.) and production operations (including fuel costs). Changes in the FSO lease rate have also been included; Changes in the FSO lease rate have also been included; the inclusion of FEED engineering costs in the FSO lease has increased the capital element by 3.8%. As a long lease item, the capital element is claimable against tax at the commencement of the lease on mobilisation to the field. The financing cost of the lease is not claimable against supplementary charge. The FSO lease day rate is fixed for the 15 year term of the lease and so that element is not escalated within the OPEX costs.

SPD costs are derived from first phase development costs escalated at 2% per year, with graduated learning curve efficiencies being applied to estimate drilling times.



Figure 10-5 Bentley FFD CAPEX schedule – annual and cumulative, escalated (1)

(1) Includes contingency

10.4. First and Second Phase OPEX

OPEX estimates have been compiled from >100 operations and activity-based costing exercises. Costs allocated to the OPEX budget, except ongoing well hook-up costs, are not eligible for capital uplift from the new Investment Allowance.

In parallel with the CAPEX review and update, OPEX costs were also updated with OPEX costs reduced by 11.2%. Key reductions are noted in well engineering, operations support services (supply boats, helicopter, communications etc.) and production operations (including fuel costs).

Figure 10-6 Bentley full field development OPEX - annual and cumulative, escalated

$0

$1,000

$2,000

$3,000

$4,000

$5,000

$6,000

$7,000

$0

$100

$200

$300

$400

$500

$600

$70020

16

2017

2018

2019

2020

2021

2022

2023

2024

2025

2026

2027

2028

2029

2039

Cum

ulat

ive

CAPE

X (U

S$M

M)

Annu

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APEX

(US$

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) Bentley Full Field Annual and Cumulative CAPEX schedule

Escalated at 2% per year ($ MM)

CAPEX Cumulative CAPEX

$0

$1,000

$2,000

$3,000

$4,000

$5,000

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$0$50

$100$150$200$250$300$350$400

2018

2020

2022

2024

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2028

2030

2032

2034

2036

2038

2040

2042

2044

2046

2048

2050

2052

2054

Cum

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Annu

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PEX

Bentley Field Annual and Cumulative OPEX Schedule Escalated at 2% per year ($MM)

Annual OPEX Cumulative OPEX



10.5. Unescalated and Escalated Costs

The unescalated costs to which escalation has been applied and the corresponding unit costs are reported in Table 10-5. Escalated costs are reported in Table 10-6.

Unescalated Costs, $MM 1P 2P 3P

Development Drilling CAPEX 2,267 2,267 2,267

Facilities CAPEX 1,268 1,268 1,268

Total CAPEX 3,535 3,535 3,535

Unit CAPEX $/bbl 14.99 13.22 11.86

OPEX 4,279 4,253 4,233

Unit OPEX $/bbl 18.1 15.9 14.2

Decommissioning 309 309 309

Unit Decom. $/bbl 1.31 1.16 1.04

Total Cost 8,123 8,097 8,077

Total Unit Cost $/bbl 34.43 30.29 27.10

Reserves MMstb 235.9 267.3 298

Table 10-5 Unescalated CAPEX and OPEX costs and unit values, Full Field

Escalated Costs, $MM 1P 2P 3P

Development Drilling CAPEX 2,668 2,668 2,668

Facilities CAPEX 1,374 1,374 1,374

Total CAPEX 4,042 4,042 4,042

Unit CAPEX $/bbl 17.13 15.12 13.56

OPEX 6,109 6,073 6,043

Unit OPEX $/bbl 25.9 22.7 20.3

Decommissioning 674 674 674

Unit Decom. $/bbl 2.86 2.52 2.26

Total Cost 10,825 10,789 10,759

Total Unit Cost $/bbl 45.89 40.36 36.10

Reserves MMstb 235.9 267.3 298

Table 10-6 Escalated CAPEX and OPEX costs and unit value, Full Field



11. Bentley Development - Economics

11.1. Assumption Register as at 31st December 2015

Xcite Working Interest: 100%

Brent Price Assumption: McDaniel January 2016 price set (1)

Bentley differential -12%

Escalation 2%/year from Jan 1st 2017

Corporate Income Tax 30%

Depreciation 100%/1st year

Tax losses carried forward $545.2 million (includes 10% RFES)

Supplementary Charge (Tax) 10% (2)

Capital uplift 62.5% (3)

RFES 10% pa on outstanding balance, 10 accounting periods (8 remaining)

Royalty Not applicable

Exchange Rate $1.5/GBP

Discount Rate 10%

P50 Abandonment Cost $309.3 million unescalated, $674.0 million escalated. Includes 20% contingency

Contingency included Yes – CAPEX and OPEX

Economic Limit Test Applied Yes

Operational uptime 96% (1st 5 years), 92.7% thereafter (includes planned and unplanned downtime)

Facilities life 35 years

Notes:

(1) McDaniel Price Forecast, 1st January 2016; Bentley price calculated at 12% discount to Brent

(2) The UK authorities had previously indicated that in the event of Brent price falling below $75/bbl the rate of supplementary charge (tax) of 20% would be re-instated and replace the 32% rate. This was done in the March 2015 budget and is effective January 2015. In the March 2016 budget this rate has been further cut to 10%. In this report it is assumed that the 10% rate of Supplementary Charge applies throughout the 35 year project life

(3) The Capital Uplift (Investment Allowance) replaced the Heavy Oil Allowance, effective date January 2015



11.2. McDaniel Price Forecast

Brent Bentley Annual % Change

2015 52.5 46.2 -47%

2016 47.5 41.8 -9.5%

2017 56.2 49.5 18.3%

2018 65.0 57.2 15.7%

2019 71.7 63.1 10.3%

2020 75.8 66.7 5.7%

2021 80.1 70.5 5.7%

2022 84.4 74.3 5.4%

2023 89.1 78.4 5.6%

2024 90.8 79.9 2.0%

2025 92.6 81.5 2.0%

2026 94.4 83.1 2.0%

2027 96.4 84.8 2.0%

2028 98.3 86.5 2.0%

2029 100.2 88.2 2.0%

2030 102.3 90.0 2.0%

Escalated at 2% p.a. thereafter

Table 11-1 McDaniel price forecast January 1st 2016, $/bbl

Independent analysis of refineries in North West Europe and the Mediterranean has identified those refineries that are best suited to running Bentley-type crudes due to their specific configuration of units as well as the metallurgy used.

The 12% discount for Bentley crude has been defined through detailed evaluation of yields and quality characteristics and valuation achieved by the market testing of Bentley crude from the EWT and the differentials realised by other heavy/sweet high TAN North Sea crudes.



11.3. Full Field Results

Under the evaluation parameters described in the assumptions register, the Bentley full field economics is positive for all cases with IRR values lying in a range of 34%-41%. All cases show production as being economic at the end of the assumed facilities life at the end of 2054 (35 years operational life), thus facilities life is the constraining factor rather than the economic limit of production in determining oil reserves.

Remaining volumes that are economic have been assigned contingent resource status, with the nature of the contingency the ability to maintain operations beyond 35 years life. Under the evaluation parameters used in this report, Bentley production remains economic for a further 15 years (P50 and P10 cases).

The 35 year design life cut-off for reserves is considered reasonable but potentially conservative - it is noted there are numerous oil and gas installations within the UKCS area (Brent, Forties etc.) that are still in operation and older than 35 years.


NPV10 $MM

NPV0 $MM

Reserves MMstb

NPV10 $/bbl

NPV0 $/bbl IRR

P90 2,070.1 7,292.2 235.9 8.8 30.9 35.0%

P50 2,496.9 9,134.1 267.3 9.3 34.2 38.8%

P10 2,866.9 10,991.9 298.0 9.6 36.9 41.1%

Table 11-2 Post-tax economic indicators and oil reserves, Full Field Development

In the P50 case, oil reserves over the period of the planned facility life sum to 267.3 MMbbls, yielding a post-tax NPV10 of $9.3/bbl and NPV0 of $34.2/bbl.

Comparing the NPV of the Full Field Development with the 2014 RAR, the negative impact of the lower oil price assumption is outweighed by the reduced costs and the reduced supplementary charge, so the NPV increases. NPV10 increases from $2,255 million to $2,497 million, while NPV0 increases from $8571 million to $9134 million. These figures are broken down and compared in Table 11-3 below.

Reserves have been revised upwards by 2 MMbbls for the P90 and P50 production cases and by 2.2 MMbbls for P10 reserves; this is primarily attributable to the faster well delivery schedule resulting in additional production within the fixed 35 year facilities life, which has been used as the cut-off point between Reserves and Contingent Resources.



P50 Undiscounted Full Field NPV0 P50 Discounted Full Field NPV10

$MM $MM Comment $MM $MM Comment

2014 NPV0 8,571 Reference 2014 NPV10 2,255 Reference

Revenue (3,192) Reduced Revenue (883) Reduced

Drillex 742 Improved Drillex 320 Improved

Facilities Capex 274 Improved Facilities Capex 209 Improved

Opex 608 Improved Opex 135 Improved

Abex 16 Improved Abex 0 Improved

Corporation Tax 503 Improved Corporation Tax 99 Improved

Supplementary Charge 1,614 Improved Supplementary

Charge 361 Improved

NPV0 563 563 Increased NPV10 242 242 Increased

2015 NPV0 9,134 2015 NPV10 2,497

Table 11-3 - Relative Cash movements from 31st December 2014 RAR

Gas production from operations is derived from 3 sources—solution gas, gas pockets encountered but below seismic resolution, and Bentley East cap gas. As the alternative fuel for process heat and power is diesel, the limited gas volumes have high value and capture of gas is thus explicit in field development planning. In estimating gas reserves, 90% of produced gas is assumed to be captured and utilized for process heat and power.



Table 11-4 Bentley gas reserves, Full Field Development

The fiscal system operated in the UK North allows an uplift of 62.5% on CAPEX and for CAPEX to be depreciated in the year incurred (100% first year allowance). A Ring Fence Expenditure Supplement (RFES) is also included which provides additional tax shelter. The RFES escalates the unrecovered balance of total expenditure (CAPEX and OPEX) by 10% per year for a maximum of ten accounting periods (years).

Graphically, Figure 11-1 below shows project revenue distribution under the P50 case (undiscounted) with operator’s net cash flow equating to 33% of project revenue and government take summing to 23%.



Figure 11-1 Full Field Development economics – P50 undiscounted revenue distribution

Analysis of project economics indicates the following schedule of reference crude prices and corresponding Bentley values required to generate zero NPV at a 10% discount rate and zero per cent discount rate.



P90 $44.87 $38.16

P50 $40.53 $34.08

P10 $37.39 $30.86

Table 11-5 Full Field Development breakeven Brent crude prices for zero NPV10 and NPV0 (1) The corresponding price realizations for Bentley crude using a 12% (negative) differential and 10% discount rate are P90 $39.49, P50 $35.67 and P10 $32.90. (2) The corresponding price realizations for Bentley crude using a 12% (negative) differential and 0% discount rate are P90 $33.6, P50 $30.0 and P10 $27.2.



Project economics was also reviewed through applying varying discount rates and calculating resulting NPVs as shown in Table 11-6 below.

Discount Rate 0% 5% 10% 15% 20%

P90 NPV $MM 7,292.2 3,763.9 2,070.1 1,169.7 650.9

P50 NPV $MM 9,134.1 4,552.5 2,496.9 1,438.1 836.4

P10 NPV $MM 10,991.9 5,294.7 2,866.9 1,652.9 974.7

Table 11-6 Full Field Development post tax NPVs at alternative discount rates

11.3.1. FFD Sensitivities

A single set of sensitivities focused on price was applied to test project performance under a +/-20% price range around the reference crude price. In all downside price cases, project economics remains positive on both a discounted and undiscounted basis.

Price Sensitivity

NPVs at Reference Crude Price Forecast -

20%

NPVs at Reference Crude Price

Forecast

NPVs at Reference Crude Price Forecast

+20%

P90 NPV10 $MM 1,240.3 2,070.1 2,852.3

P90 NPV0 $MM 4,791.1 7,292.2 9,793.4

P50 NPV10 $MM 1,604.0 2,496.9 3,354.1

P50 NPV0 $MM 6,268.9 9,134.1 12,004.5

P10 NPV10 $MM 1,908.3 2,866.9 3,794.9

P10 NPV0 $MM 7,758.9 10,991.9 14,240.5

Table 11-7 Full Field Development price sensitivities, discounted and un-discounted NPVs

11.4. First Phase Development – Summary Economics

As part of the phased field development plan for Bentley, CAPEX and summary economics for the FPD is reported in this section on a standalone basis as part of the full field development. The evaluation uses the same assumptions as the full field development and is reported on the basis of a facilities life of 35 years.



Table 11-8 First Phase Development annual and cumulative CAPEX


NPV10 $MM

NPV0 $MM

Reserves MMstb

NPV10 $/bbl

NPV0 $/bbl

IRR

P90 1,614.5 5,098.0 158.9 10.2 32.1 35.8%

P50 1,951.3 6,429.5 182.7 10.7 35.2 39.7%

P10 2,239.7 7,769.1 205.6 10.9 37.8 41.9%

Table 11-9 Post-tax economic indicators and oil reserves, First Phase Development

The associated gas reserves for the FPD are reported in Table 11-10 :



Table 11-10 Bentley gas reserves, First Phase Development

Analysis of project economics indicates the following schedule of reference crude prices required to generate zero NPV at 10% discount rate for the FPD case.





P90 $43.30 $37.0

P50 $38.73 $32.62

P10 $35.59 $29.28

Table 11-11 First Phase Development breakeven Brent crude prices for zero NPV10 and NPV0

(1) The corresponding price realizations for Bentley crude using a 12% (negative) differential are P90 $38.14, P50 $34.08 and P10 $31.50. (2) The corresponding price realizations for Bentley crude using a 12% (negative) differential and 0% discount rate are P90 $32.6, P50 $28.7 and P10 $25.8.

As with the Full Field Development case, the FPD was also reviewed using alternative discount rates and calculating NPVs as shown in Table 11-12.

Discount Rate 0% 5% 10% 15% 20%

P90 NPV $MM 5,098.0 2,773.8 1,614.5 962.4 564.0

P50 NPV $MM 6,429.5 3,370.3 1,951.3 1,182.2 720.7

P10 NPV $MM 7,769.1 3,930.9 2,239.7 1,353.7 833.8

Table 11-12 First Phase Development post tax NPVs at alternative discount rates

11.4.1. FPD Sensitivities

A single set of sensitivities focused on price was applied to test project performance under a +/-20% price range around the reference crude price forecast. In all downside price cases, project economics remains positive on both a discounted and undiscounted basis.

Price Sensitivity NPVs at Reference Crude Price -20%

NPVs at Reference Crude Price Forecast

NPVs at Reference Crude Price +20%

P90 NPV10 $MM 1,019.9 1,614.5 2,169.6

P90 NPV0 $MM 3,470.9 5,098.0 6,740.4

P50 NPV10 $MM 1,311.0 1,951.3 2,571.5

P50 NPV0 $MM 4,535.9 6,429.5 8,353.4

P10 NPV10 $MM 1,549.5 2,239.7 2,915.7

P10 NPV0 $MM 5,605.2 7,769.1 9,967.6

Table 11-13 First Phase Development price sensitivities, discounted and un-discounted NPV



12. Appendix 1 Summary Tables

12.1. Oil and Gas Reserves

SUMMARY OF OIL AND NATURAL GAS RESERVES

(Forecast prices and costs)

Heavy Oil Natural Gas (1)

Gross Net Gross Net

Reserves Category (MMstb) (MMstb) (Bcf) (Bcf)

Proved Developed 0.00 0.00 0.0 0.0

Developed Non-Producing 0.00 0.00 0.0 0.0

Undeveloped 235.88 235.88 22.9 22.9

Total Proved (1P) 235.88 235.88 22.9 22.9

Probable 31.46 31.46 13.0 13.0

Proved plus Probable (2P) 267.33 267.33 35.9 35.9

Possible 30.70 30.70 13.5 13.5

Proved plus Probable plus Possible (3P) 298.03 298.03 49.4 49.4

Notes: (1) Natural gas reserves - assumes that 90% of produced gas is used for process heat and power.



12.2. Net Present Value at Alternative Discount Rates

Before Income Tax Unit Value(4) Before

Income Tax Discounted at Discounted at 0%/yr. 5%/yr. 10%/yr. 15%/yr. 20%/yr. 10%/yr. Reserves Category $MM $MM $MM $MM $MM $/bbl PROVED Developed Producing - - - - - - Developed Non-Producing - - - - - - Undeveloped 10624.8 5292.3 2835.4 1581.8 885.9 11.8 TOTAL PROVED (1P) 10624.8 5292.3 2835.4 1581.8 885.9 11.8 TOTAL PROBABLE 3134.6 1325.0 695.1 418.9 275.9 20.7 TOTAL PROVED + PROBABLE (2P)

13759.4 6617.3 3530.5 2000.6 1161.8

12.9

TOTAL POSSIBLE 3134.6 1245.8 610.2 344.2 213.6 18.5 TOTAL PROVED + PROBABLE + POSSIBLE (3P)

16894.0 7863.1 4140.8 2344.8 1375.4

13.5

After Income Tax Unit Value(4) After

Income Tax Discounted at Discounted at 0%/yr. 5%/yr. 10%/yr. 15%/yr. 20%/yr. 10%/yr. Reserves Category $MM $MM $MM $MM $MM $/bbl PROVED Developed Producing - - - - - - Developed Non-Producing - - - - - - Undeveloped 7292.2 3763.9 2070.1 1169.7 650.9 8.6 TOTAL PROVED (1P) 7292.2 3763.9 2070.1 1169.7 650.9 8.6 TOTAL PROBABLE 1841.8 788.5 426.7 268.4 185.5 12.7 TOTAL PROVED + PROBABLE (2P)

9134.1 4552.5 2496.9 1438.1 836.4

9.1

TOTAL POSSIBLE 1857.9 742.2 370.00 214.8 138.4 11.2 TOTAL PROVED + PROBABLE + POSSIBLE (3P)

10991.9 5294.7 2866.9 1652.9 974.7

9.4

Notes:

(1) UK Corporation Tax is charged at the rate of 30% on net taxable income.

(2) UK Supplementary Charge ("SC") is charged at the rate of 10% on net taxable income with no deduction for finance charges and interest.

(3) An Investment Allowance of 62.5% of allowable Capital expenditure has been applied to offset the SC to the extent possible.

(4) In this calculation, gas reserves used in field operations (utilities and process heat) have been added to oil reserves using a conversion factor of 6,000 cubic feet of gas per barrel of oil equivalent (BOE)



12.3. Revenue Distribution

TOTAL FUTURE NET REVENUE (Undiscounted)

(Forecast prices and costs as at 31st December 2015)

Reserves Category Revenue

$MM Royalties

$MM

Operating Costs $MM

Development Costs $MM

Abandonment and

Reclamation Costs $MM

Future Net Revenue Before Income Taxes $MM

Income Taxes $MM

Future Net Revenue

After Income Taxes $MM

TOTAL PROVED (1P) 21,449.7

- 6,109.4 4,041.5 674.0 10,624.8 3,332.6 7,292.2

TOTAL PROVED PLUS PROBABLE (2P)

24,547.8 -

6,072.8 4,041.5 674.0 13,759.4 4,625.4 9,134.1

TOTAL PROVED PLUS PROBABLE PLUS POSSIBLE (3P)

27,652.0 -

6,042.5 4,041.5 674.0 16,894.0 5,902.1 10,991.9



12.4. Development Costs

FUTURE DEVELOPMENT COSTS ATTRIBUTABLE TO RESERVES

(Undiscounted) (Forecast prices and costs)

Year

Total Proved Estimated

($MM)

Total Proved Plus Probable Estimated

($MM)

Total Proved Plus Probable Plus Possible

Estimated ($MM)

Bentley Field

2016 109.45 109.5 109.5

2017 275.74 275.7 275.7

2018 144.59 144.6 144.6

2019 194.96 195.0 195.0

2020 236.02 236.0 236.0

2021 329.19 329.2 329.2

2022 518.26 518.3 518.3

2023 365.68 365.7 365.7

2024 539.02 539.0 539.0

2025 445.71 445.7 445.7

Thereafter 882.92 882.9 882.9

Total for all years undiscounted 4,041.5 4,041.5 4,041.5

Note:

(1) The capital expenditure and construction schedule of FPD and Phase 2 is assumed to be the same for the Proved (1P), Proved plus Probable (2P) and Proved plus Probable plus Possible (3P) outcomes. Hence the estimated future development costs are assumed to be the same for all three outcomes.



12.5. Pricing Assumptions

The Report employs the following pricing assumptions for crude oil as set out below, taken from the McDaniel forecast with effect from January 1, 2016 as published at www.mcdan.com. Commencing with this price forecast, the Report has applied a 12% reduction in the revenue from the sale of crude oil to take account of the assumed discount of Bentley heavy oil to the Brent crude price. The Report uses a 2% per annum escalation in costs starting in 2017.

Year Brent

Bentley % change Cost

Inflation 2016 47.50 41.80 - 0% 2017 56.20 49.46 18% 2% 2018 65.00 57.20 16% 2% 2019 71.70 63.10 10% 2% 2020 75.80 66.70 6% 2% 2021 80.10 70.49 6% 2% 2022 84.40 74.27 5% 2% 2023 89.10 78.41 6% 2% 2024 90.80 79.90 2% 2% 2025 92.60 81.49 2% 2% 2026 94.40 83.07 2% 2% 2027 96.40 84.83 2% 2% 2028 98.30 86.50 2% 2% 2029 100.20 88.18 2% 2% 2030 102.30 90.02 2% 2% 2031 104.35 91.82 2% 2% 2032 106.43 93.66 2% 2% 2033 108.56 95.53 2% 2% 2034 110.73 97.44 2% 2% 2035 112.95 99.39 2% 2% 2036 115.21 101.38 2% 2% 2037 117.51 103.41 2% 2% 2038 119.86 105.48 2% 2% 2039 122.26 107.59 2% 2% 2040 124.70 109.74 2% 2% 2041 127.20 111.93 2% 2% 2042 129.74 114.17 2% 2% 2043 132.34 116.46 2% 2% 2044 134.98 118.78 2% 2% 2045 137.68 121.16 2% 2% 2046 140.44 123.58 2% 2% 2047 143.24 126.06 2% 2% 2048 146.11 128.58 2% 2% 2049 149.03 131.15 2% 2% 2050 152.01 133.77 2% 2% 2051 155.05 136.45 2% 2% 2052 158.15 139.18 2% 2% 2053 161.32 141.96 2% 2% 2054 164.54 144.80 2% 2%

http://www.mcdan.com/



12.6. Contingent Resources

Contingent Resources attributable to Xcite in their UKCS Northern North Sea blocks are restricted to oil and gas volumes that are notionally producible after 2051 from Phase 1 and Phase 2 of the Bentley field development. The nature of the contingency is the 35 year design life of the facilities.

SUMMARY OF OIL AND NATURAL GAS CONTINGENT RESOURCES (Forecast prices and costs)

Heavy Oil Natural Gas (1) Gross Net Gross Net Block Contingent Resources (MMstb) (MMstb) (BCF) (BCF) 9/3b MEAN 12.2 12.2 1.4 1.4

9/3b P90 (1C) - - - -

9/3b P50 (2C) 9.3 9.3 0.9 0.9

9/3b P10 (3C) 28.1 28.1 3.3 3.3

(1) Natural gas Contingent Resources - assumes that 90% of produced gas is used for process heat and power.



12.7. Prospective Resources

Prospective resources are those quantities of petroleum estimated, as of a given date, to be potentially recoverable from undiscovered accumulations by application of future development projects. Prospective resources have both an associated chance to discover and a chance of development.


P90 MMstb

P50 MMstb

P10 MMstb

Probability of Geologic Success,

Pg (1)

Pg- Adjusted Mean

Estimate

Clement

Oil Resources 9/4a 4.7 0.9 3.1 10.2 21% 1.0

Chadwick

Oil Resources, 9/4a 30.6 10.5 24.6 57.8 21% 6.4

Cartwright

Oil Resources 9/4a 19.3 8.6 16.9 33.2 16% 3.1

Camm

Oil Resources 9/8b, 9/9h 15.0 2.6 9.4 34.6 18% 2.7

Notes:

(1) Pg is the geological success that the unrisked hydrocarbon volume will be found

There is no certainty that any portion of the prospective resources will be discovered. If discovered, there is no certainty that it will be comercially viable to produce any portion of the prospective resources set forth in the table above



13. Appendix 2 Glossary

In this Report, the following words have the meanings as set out below :

"1P" means proved reserves, which are those quantities that are estimated with a high degree of certainty to be recoverable.

"2P" means proved plus probable reserves. Probable reserves are those quantities of additional reserves that are less certain to be recovered than proved reserves. It is equally likely that the actual remaining quantities recovered will be greater or less than the sum of the estimated proved plus probable reserves.

"3P" means proved plus probable plus possible reserves. Possible reserves are those additional reserves that are less certain to be recovered that probable reserves and there is a 10% probability that the quantities actually recovered will equal or exceed the sum of the estimated proved plus probable plus possible reserves.

“BCF” means billion cubic feet of gas

"Best estimate" is considered to be the best estimate of the quantity that will actually be recovered. It is equally likely that the actual remaining quantities recovered will be greater or less than the best estimate. If probabilistic methods are used, there should be at least a 50 percent probability (P50) that the quantities actually recovered will equal or exceed the best estimate.

"BOE" means barrels of oil equivalent. BOE’s, derived by converting gas to oil in the ratio of six thousand cubic feet of gas to one barrel of oil, may be misleading, particularly if used in isolation. A boe conversion is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead.

"Contingent Resources" means those quantities of petroleum estimated, as of a given date, to be potentially recoverable from known accumulations using established technology or technology under development, but which are not currently considered to be commercially recoverable due to one or more contingencies. Contingencies may include factors such as economic, legal, environmental, political, and regulatory matters, or a lack of markets. There is no certainty that it will be commercially viable to produce any portion of the Contingent Resources.

"Bentley" development means FPD and SPD.

"DECC" means UK Department of Energy and Climate Change.

“FFD” means Full Field Development.

“FPD” means First Phase Development.

“GIIP” means Gas Initially In Place.

"High estimate" is considered to be an optimistic estimate of the quantity that will actually be recovered. It is unlikely that the actual remaining quantities recovered will exceed the high estimate. If probabilistic methods are used, there should be at least a



10 percent probability (P10) that the quantities actually recovered will equal or exceed the high estimate.

"Low estimate" is considered to be a conservative estimate of the quantity that will actually be recovered. It is likely that the actual remaining quantities recovered will exceed the low estimate. If probabilistic methods are used, there should be at least a 90 percent probability (P90) that the quantities actually recovered will equal or exceed the low estimate.

"MM" means millions.

"MMbbls" means millions of barrels.

"MMboe" means millions of barrels of oil equivalent.

"MMstb" means millions of stock tank barrels.

"NPV0" means net present value in money of the day using a 0% forward discount rate, which values do not represent fair value.

"NPV10" means net present value in money of the day using a 10% forward discount rate, which values do not represent fair value.

“OGA” means the Oil and Gas Authority.

“PIIP” means petroleum initially in place.

"Prospective resources" means those quantities of petroleum estimated, as of a given date, to be potentially recoverable from undiscovered accumulations by application of future projects. There is no certainty that any portion of the prospective resources will be discovered. If discovered, there is no certainty that it will be commercially viable to produce any portion of the prospective resources.

"SPD" means the Second Phase Development.

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Reserves and Resource Assessment of the Bentley … · Reserves and Resource Assessment of the Bentley Field ... Petrel Model ... Reserves and Resource Assessment Report of the Bentley