CORPORATE PRESENTATION June 2014 Legal Disclaimer The information - - PowerPoint PPT Presentation

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CORPORATE PRESENTATION June 2014 Legal Disclaimer The information - - PowerPoint PPT Presentation

CORPORATE PRESENTATION June 2014 Legal Disclaimer The information contained in this presentation (Presentation) has been prepared by Xcite Energy Limited Actual future net cash flows also will be affected by other factors such as actual


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SLIDE 1

CORPORATE PRESENTATION June 2014

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SLIDE 2

June 2014

Legal Disclaimer

2

The information contained in this presentation (“Presentation”) has been prepared by Xcite Energy Limited (“Xcite Energy” or “Company”) and is being delivered for informational purposes only. The information contained in this Presentation is provided as at the date hereof and is subject to change without notices and does not purport to contain all information about the Company. Certain statements contained in this Presentation constitute forward-looking information within the meaning

  • f securities laws, including statements relating to the estimated reserves, resources and exploration activities

associated with the oil and gas properties in which the Company holds an interest. All information other than information of historical fact is forward-looking information. Forward-looking information may relate to the Company’s future outlook and anticipated events or results and, in some cases, can be identified by terminology such as “may”, “will”, “should”, “expect”, “plan”, “anticipate”, “believe”, “intend”, “estimate”, “predict”, “project”, “target”, “potential”, “continue” or other similar expressions concerning matters that are not historical facts, and are intended to identify forward-looking information. No assurance can be given that this information will prove to be correct and such forward looking information included in this presentation should not be unduly relied on. These statements are based on certain factors and assumptions including expected growth, results of operations, performance and business prospects and opportunities. While the Company considers these assumptions to be reasonable based on information currently available to it, they may prove to be incorrect. Forward-looking information is also subject to certain factors, including risks and uncertainties that could cause actual results to differ materially from what we currently expect. These factors include risks associated with the oil and gas industry (including operational risks in development, exploration and production, delays or changes in plans with respect to exploration or development projects or capital expenditures, the uncertainty of reserves and resources estimates and projections in relation to production, costs and expenses, health, safety and environmental risks and offshore exploration risk), the risk of commodity price and foreign exchange rate fluctuations and the ability of the Company to secure financing. Additional information identifying risks and uncertainties are contained in the Company’s annual information form dated 26 October, 2010 and in the Management's Discussion and Analysis for Xcite Energy dated 26 March 2014, filed with the Canadian securities regulatory authorities and available at www.sedar.com. The Company disclaims any intention or obligation to update or revise any forward-looking statements whether as a result of new information, future events or otherwise, except as required under applicable securities regulations. Statements relating to “reserves” or “resources” are deemed to be forward-looking statements or information, as they involve the implied assessment, based on certain estimates and assumptions, that the resources and reserves described can be profitable in the future. There are numerous uncertainties inherent in estimating quantities of proved reserves, including many factors beyond the control of the Company. The reserve and resources data included herein represents estimates only. In general, estimates of economically recoverable

  • il reserves and the future net cash flows therefrom are based upon a number of variable factors and

assumptions, such as historical production from the properties, the assumed effects of regulation by governmental agencies and future operating costs, all of which may vary considerably from actual results. All such estimates are to some degree speculative and classifications of reserves are only attempts to define the degree of speculation involved. For those reasons, estimates of the economically recoverable oil reserves attributable to any particular group of properties and classification of such reserves based on risk of recovery and estimates of future net revenues expected therefrom, prepared by different engineers or by the same engineers at different times, may vary substantially. The actual production, revenues, taxes and development and operating expenditures of the Company with respect to these reserves will vary from such estimates, and such variances could be material. The reserves, resources and future net revenue from the Company’s properties have been independently audited by TRACS International Consultancy Ltd (“TRACS”) in its Reserves Assessment Report (“RAR”) of the Company’s properties dated 25 February 2014 and effective 31 December 2013. Reference is made to the Company’s Statement of Reserves Data and Other Oil and Gas Information (Form 51-101F1) report dated 25 February 2014 for more information about the reserves and resources information prepared by TRACS for the Company. Consistent with the securities disclosure legislation and policies of Canada, forecast prices and costs are used in calculating reserve quantities included herein. Actual future net cash flows also will be affected by other factors such as actual production levels, supply and demand for oil and natural gas, curtailments or increases in consumption by oil and natural gas purchasers, changes in governmental regulation or taxation and the impact of inflation on costs. The estimated future net revenue contained herein does not necessarily represent the fair market value of the Company’s reserves and resources. There is no assurance that the forecast price and cost assumptions contained in the RAR will be attained and variances could be material. The recovery and reserves estimates on the Company’s properties described herein are estimates only. The actual reserves on the Company’s properties may be greater or less than those calculated. All recipients of this Presentation are encouraged to obtain separate and independent verification of information and opinions contained in this Presentation as part of their own due diligence. This Presentation should not be considered as the giving of investment advice by the Company or any of its shareholders, directors, officers, agents, employees or advisors. Each party to whom this Presentation is delivered or made must make its own independent assessment of the Company after making such investigations and taking such advice as may be deemed necessary. In particular, any estimates or projections

  • r opinions contained in this Presentation necessarily involve significant elements of subjective judgement,

analysis and assumption and each recipient should satisfy itself in relation to such matters. In no circumstances will the Company be responsible for any costs, losses or expenses incurred in connection with any appraisal or investigation of the Company. This Presentation does not constitute, or form part of, any offer or invitation to sell or issue, or any solicitation

  • f any offer to subscribe for or purchase any securities in the Company, nor shall it, or the fact of its delivery,

making or distribution, form the basis of, or be relied upon in connection with, or act as any inducement to enter into any contract or commitment whatsoever with respect to such securities. The delivery, making or distribution of this Presentation in or to persons in certain jurisdictions may be restricted by law and persons who receive this Presentation should inform themselves about, and observe, any such restrictions. Any failure to comply with these restrictions may constitute a violation of the laws of the relevant jurisdiction. In particular, this Presentation has not been approved by an authorised person pursuant to Section 21 of the Financial Services and Markets Act 2000 (“FSMA”) and accordingly, it is being communicated in the United Kingdom only to persons to whom this Presentation may be communicated without contravening the financial promotion prohibition in Section 21 of the FSMA. Those persons are described in the Financial Services and Markets Act 2000 (Financial Promotion) Order 2005 (“Order”) and include persons who fall within the category of person set out in Articles 19(5) and 49(2) of the Order. In addition, in the United Kingdom, this Presentation is only being communicated to and directed at persons who are a “qualified investor” (within the meaning of Section 86(7) of the FSMA) acting as principal or in circumstances to which Section 86(2) of the FSMA applies. Any investment activity to which this Presentation relates in the United Kingdom is available to, and will only be engaged with such persons and this Presentation should not be acted or relied upon in the United Kingdom by persons of any other description. No offer of securities in the Company is being or will be made in the United Kingdom in circumstances which would require a prospectus to be approved by the UK Financial Services Authority (“FSA”) under Section 87A of the FSMA. By accepting this Presentation, the recipient represents and warrants that it is a person to whom this Presentation may be delivered or distributed without a violation of the laws of any relevant jurisdiction. This Presentation is not to be disclosed to any other person or used for any other purpose and any other person who receives this Presentation should not rely or act upon it. Nothing in this disclaimer shall limit or exclude any liability which by law or regulation cannot be limited or excluded. See the slide titled “Glossary” at end of Presentation for definitions of those defined terms in the Presentation.

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SLIDE 3

June 2014

Investment Highlights

  • One of the largest, proven and undeveloped oil fields in the UK North Sea
  • Independently verified: 257 MMstb 2P Reserves; 48 MMstb Contingent Resources
  • 35 year production profile; first phase peak production of 45,000 bbls per day

3

Major UK North Sea Asset USD 250m EWT to De-risk Development Plan

  • Full production package - drilling, production, flow assurance, FSO dehydration and marketing
  • Generated significant data to understand reservoir behaviour and performance
  • 68 day test; 57 days uptime; max flow of 3,500 bbls/day per lateral; 149,000 bbls crude oil produced

Thoroughly Appraised Reservoir

  • 8 penetrations, including 3 wells and 2 horizontal laterals drilled by Xcite

– 9/3b-5 well drilled in 2008: flowed oil to surface – 9/3b-6 well drilled in 2010: proved horizontal well and commercial flow rate – 9/3b-7 well drilled in 2012: multi-lateral Extended Well Test

Partners and Engineering De-risk Cost and Schedule

  • MOU with Teekay for bridge linked Sevan FSO
  • MOU with AMEC and Arup for self-installing ACE production platform
  • Further engineering in 2014, ahead of FDP submission to de-risk project costs and schedule

Robust Economics and Fiscal Incentives

  • P50 NPV10 breakeven Brent oil price USD 43.7/bbl (RAR, 25 Feb 2014, escalated)
  • USD 380m capital allowance loss pool
  • Eligible for GBP 800m ultra heavy oil allowance (subject to HMRC approval)

Experienced Management Team

  • Successfully delivered the USD 250m Extended Well Test, safely, on-schedule and on-budget
  • One of the largest stand-alone projects delivered in the in UK North Sea in 2012
  • XER managed the contractor group of major service companies
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SLIDE 4

June 2014

Table of Contents Introduction to Xcite Energy Bentley Field – Extended Well Test Bentley Field – Development Plan Financing strategy and Economics Timeline and Investment Highlights Appendix

4

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SLIDE 5

June 2014

Introduction to Xcite Energy

Overview Independent Certified Reserves and Resources 35 year production profile

5

  • E&P independent listed on AIM (London) & TSX-V

(Toronto), ticker XEL

  • 100% holder of 4 licences over 6 blocks in UK North

Sea

  • Key asset: Bentley field, 257 MMstb 2P Reserves and

48 MMstb P50 Contingent Resources

  • 35 year production profile; projected first phase peak

production of 45,000 bbls/day

  • USD 250m Extended Well Test (“EWT”) proved key

technical and commercial aspects of the field and simplified development plan

  • Key development partners being selected – MOUs

signed with Teekay, AMEC and Arup

  • Next phase of pre-FEED/assurance engineering with

partners to optimise development concept and refine costs and schedule for project execution

  • Intention to sign binding contracts, subject to FDP

approval, once engineering completed by end of 2014

Strategy to Reduce Project Risk by EWT and Upfront Engineering

50 100 150 200 250 300 350 400 1P (P90) 2P (P50) 3P (P10) MMstb Reserves Contingent Resources

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SLIDE 6

June 2014

Experienced Management Team

Jon Dale

Finance Director

  • Joined Xcite in 2008
  • Over 15 years

experience in the oil industry, including 7 years with PwC providing audit and transaction support services to clients in the oil and gas industry

Barny Brennan

Subsurface Director

  • Joined Xcite in 2008
  • Over 25 years oil

industry experience having been responsible for Senergy London region, following 15 years with Phillips Petroleum

Charles Lucas-Clements

BD & Strategy Director

  • Joined Xcite in 2008
  • Over 30 years

expertise in oil and gas development, specialising in exploitation of challenging fields, advising multinationals, independent oil companies and governments

Matt Bower

Operations Director

  • Joined Xcite in 2012
  • Experienced Master

Mariner with over 20 years operational and project management experience in offshore

  • il and gas with

Bluewater and Maersk FPSO

Andrew Fairclough

Chief Financial Officer

  • Joined Xcite in 2012
  • Executive Director of

Xcite in 2014

  • Over 17 years

investment banking and capital markets experience at a number of financial institutions including Merrill Lynch and Rothschild

Rupert Cole

Chief Executive Officer

  • Founder and

Executive Director of Xcite since 2003

  • Chief Financial Officer

until 2012

  • Chartered Accountant

with over 25 years corporate finance experience

Steve Kew

Chief Operating Officer

  • Founder and

Executive Director of Xcite since 2003

  • 25 years with Conoco

in a wide variety of roles

  • Heavy Oil expertise,

including as a former consultant to DECC

6

Delivered the USD250m Extended Well Test in the North Sea, on-time and on- budget with no safety or environmental incident or impact

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SLIDE 7

June 2014

7

  • The Bentley field is located in Block 9/3b, in the UK North Sea
  • Approx 160km east of the Shetland Isles, in 113m water depth
  • Large areal extent – 15km x 6km
  • P50 in-place volume of 907 MMstb
  • Clearly defined, four-way dip structure

High Quality Reservoir Supports Commercial Productivity

  • High net to gross: 93%
  • High porosity: 31%
  • Ultra-high effective permeability: 47 Darcies
  • Heavy oil 10-12o API, 1500 cP
  • Oil-leg up to 120ft in depth
  • Underlying aquifer up to 400 ft in depth,

estimated at 10 billion barrels

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SLIDE 8

June 2014

Well Appraised and Understood Heavy Oil Field

Well Name Completed Operator Hydrocarbons Tests 9/3-1 1977 Amoco Encountered 12° API oil – 81 ft oil column Nitrogen evacuation. Oil too heavy to flow (no pump) 9/3-2A 1983 Conoco 92 ft oil column ESP lifted DST. No flow due to pump failure 9/3-3 1986 Conoco Dry hole on separate structure None 9/3-4 1986 Conoco 84 ft oil column Not tested (commitment well, low oil price environment) Well Name Completed Operator Hydrocarbons Tests 9/03b-5 2008 Xcite 87 ft oil column ESP lifted, average 125 stb/day with high skin 9/03b-6 2010 Xcite 113 ft oil column Logged and pressure tested 9/03b-6Z 2010 Xcite 1,821 ft oil section (horizontal) ESP lifted, 36hr DST reaching stabilized 2,900 stb/day 9/03b-7 2012 Xcite 2,214 ft oil section (horizontal) ESP lifted extended flow test, reaching 3,500 stb/day 9/03b-7Z 2012 Xcite 2,042 ft oil section (horizontal) ESP lifted extended flow test

Pre-Xcite Wells – 1970s and 1980s Xcite Wells – 5 successful penetrations

8

  • Since 1977, Bentley has been

appraised with a total of 8 reservoir penetrations

  • Latest 3D seismic shot in 2011
  • Xcite has drilled 3 wells plus 2

horizontal laterals, including a 68 day pre-production EWT

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SLIDE 9

June 2014

Source: CPR / RAR: 1, RPS, Sep 2006; 2, RPS, Sep 2007; 3, RPS, Feb 2009; 4, TRACS, May 2011; 5, TRACS, Feb 2012; 6, TRACS, Apr 2013; 7, TRACS, Feb 2014

50 100 150 200 250 300 350 400 450 2007 2009 2011 2012 2013 2014

2P Reserves Contingent Resources Prospective Resources (unrisked)

2

9/3b-6/6Z Well 9/3b-7/7Z Well 9/3b-5 Well 2008 2010 2012

  • Xcite appraisal programme has led to a steady

progression in reserves

  • Approx USD350m invested in three well

programmes

  • 257 MMstb 2P Reserves
  • 48 MMstb 2C Contingent Resources
  • Independently verified by reserves auditor at each stage

MMstb

NPV10 $340m

1

NPV10 $781m

3

NPV10 $1.36bn

4

NPV10 $1.46bn

5

NPV10 $2.17bn

6

NPV10 $2.11bn

7

Progressive Increase in Reserves and Resources

PIIP for Bentley Field Mean P90 P50 P10 Total PIIP (MMstb) 909 768 907 1052 Bentley Field Oil 1P 2P 3P Reserves (MMstb) 204 257 317 NPV10 (US$m)* 1,468 2,112 2,729 Bentley Field Gas P90 P50 P10 Reserves bcf 26 32 41 Contingent Oil Resources Mean P90 P50 P10 MMstb 49 36 48 63 Prospective Oil Resources** Mean P90 P50 P10 MMstb 96 39 79 174

Reserves Assessment Report, AGR TRACS 25 February 2014 * Based on crude oil pricing assumptions taken from the McDaniel forecast with effect from 1 October 2013, applying 12% assumed discount for Bentley crude. 2% costs escalation from 1 January 2014 ** Aggregate of all prospects, unrisked There is no certainty that it will be commercially viable to produce any portion of the resources. 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 set forth in the table above. The prospective resource sums are arithmetic sums. With respect to the high estimate total for the prospective resources, volume is an arithmetic sum of multiple estimates of prospective resources, which statistical principles indicate may be misleading as to volumes that may actually be recovered. Readers should give attention to the estimates of individual classes of prospective resources as included in the Company’s Reserves Assessment Report dated 25 February 2014 as summarised in the NI51-101F1 published on 25 February 2014 and appreciate the differing probabilities of recovery associated with each class as set out therein.

9

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SLIDE 10

June 2014

10

  • Bentley is currently one of the largest, proven and undeveloped assets in the UK North Sea
  • Long reserves production profile extending to 35 years, and beyond to 50 years assuming contingent resources

converted to reserves

  • Optimisation and Enhanced Oil Recovery expected to further increase reserves

One of the Largest, Proven and Undeveloped Assets in the UK North Sea

Source: Wood MacKenzie database for all other fields than Bentley. Certified 2P reserves for Bentley as of 31.12.2013. Source: DECC, UK Annual Oil Production by Field, 1 Apr 2014. Cubic metres converted to bbls at conversion ratio

  • f 2.898.

* Bentley projected data, as currently modelled by the Issuer

Oil fields UKCS (remaining reserves) 2013 UKCS Oil Production

50 100 150 200 BUZZARD FORTIES CAPTAIN FOINAVEN ALBA NELSON DON SOUTH WEST BACCHUS NINIAN TELFORD CLAIR HARDING MACHAR FRANKLIN CALLANISH ETTRICK BERYL BLAKE CORMORANT NORTH SCOTT

Mstb/day

Bentley projected second phase peak production, 57,000 bbls/day* Bentley projected production after 17 years (c.15,000 bbls/day)* Bentley projected production after 35 years (c.8,500 bbls/day)*

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SLIDE 11

June 2014

Introduction to Xcite Energy Bentley Field – Extended Well Test Bentley Field – Development Plan Financing strategy and Economics Timeline and Investment Highlights Appendix

11

Table of Contents

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SLIDE 12

June 2014

Extended Well Test: Proving the Development Concept

12

Principal Technical Objectives

  • Safety & Environmental compliance
  • Drilling and completion techniques
  • Multi-lateral well technology
  • Water ingress and interaction with oil
  • Flow assurance and production chemistry
  • Calibrate reservoir models

Principal Commercial Objectives

  • Proof of technical and commercial performance criteria
  • Verify the marketability of the crude
  • Demonstrate that Xcite can deliver a major project safely,
  • n-budget and on-schedule
  • Validate the projected development concept = scale-up of

EWT

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SLIDE 13

June 2014

Xcite Managed Service Providers and Produced c.149,000 Barrels of Bentley Oil

13 9 Mattresses

  • Heated, de-gassed and co-flowed with water
  • Blending managed to optimise marketability
  • Confirmed viability of FSO dehydration solution and offtake to market

Rig to Tanker offset 1.5 km – 1.7 km Tether base & 8 Mattresses

1 x 300m “Lazy S” Riser with distributed buoyancy

Water Depth 113m Shuttle tanker with 750,000 bbls Storage

Tanker Manifold Coupling Head Upper Hose

(5 x 300m seabed lay)

Swivel

1 x ‘Pipeline Chute’ with max tension safety device (1 x 300m ‘J Lay’ Riser) Jack-Up Drilling Rig ‘Rowan Norway’

De-gas Dehydrate Blend

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SLIDE 14

June 2014

EWT Designed to Test Water Cut and Long Term Productivity

9/3e

14

  • Demonstrated

successful multi-lateral drilling

  • 9/03b-7

(B6) lower lateral well geosteered 60ft above OWC to ensure water break-through and measure increase in water cut during test period

  • 9/03b-7Z

(B5) upper lateral well geosteered 5-10 ft from reservoir roof, flowed and left as future producer

  • 3750
  • 3700
  • 3650
  • 3600
  • 3550

1000 1500 2000 Depth (ft TVDSS) Offset (m)

B6 Trajectory

B6 Top Dornoch OWC Top of Reservoir

Wellbore Path Oil water Contact (OWC)

  • 3750
  • 3700
  • 3650
  • 3600
  • 3550

1000 1500 2000 Depth (ft TVDSS) Offset (m)

B5 Trajectory

B5 Top Dornoch OWC Oil water Contact (OWC) Wellbore Path Top of Reservoir

Top Balder Top Dornoch In Top Dornoch Out Well 7Z Well 7 Top Dornoch RNS Mid Top Dornoch RNS End

Well 6Z Well 6

  • Wells flowed for 57 days uptime, within 68 day test period which

included shut-ins/build-ups, production chemistry, etc

  • Water break through better than expectations
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SLIDE 15

June 2014

Key Development Questions Answered

Question How Xcite has addressed this Is there sufficient oil in the ground for a viable development? What is the nature of Bentley fluid and its flowing properties? Can Bentley fluid be flowed at commercial rates? Can oil-rate be sustained following water break-through? Can development plan contact a large area of the field at reasonable cost? Can produced fluids be processed and exported efficiently? Can exported fluids be sold at a reasonable market price?

Mapping has consistently shown large in-place volume. Current P50 = 907 MMstb Vertical well 9/03b-5 flowed first oil and provided data to predict flowing properties Horizontal well 9/03b-6Z flowed at 2,900 stb/day per

  • lateral. Re-confirmed with 9/03b-7, 7Z, reaching 3,500

stb/day per lateral Horizontal well 9/03b-7 EWT demonstrated better than expected water break through behaviour Long-reach, multi-lateral, horizontal wellbores. Over 6,000 ft reservoir drilled to date confirmed methodology Processed and delivered export quality crude to

  • market. Dehydration in 8-12 days = FSO solution
  • Approx. 150,000 stb Bentley crude sold supporting a

12% discount to Brent

15

      

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SLIDE 16

June 2014

Introduction to Xcite Energy Bentley Field – Extended Well Test Bentley Field – Development Plan Financing strategy and Economics Timeline and Investment Highlights Appendix

16

Table of Contents

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SLIDE 17

June 2014

Upfront Engineering is Intended to De-Risk Future Costs and Schedule

Project Teams Project Teams Decision Makers Decision Makers

IDENTIFY DEVELOP SELECT EXECUTE OPERATE

Identify Evaluate Alternatives Y/N FEED Funding Request Choose Report Development Planning Operations Acceptance Report Metrics Y/N Y/N Construct

Field Development Plan Approval Accelerate cost definition ahead

  • f submission of

FDP

Class 5 Class 4 Class 3 Class 2 Class 1 (As Built) Cost/Schedule Precision 0-2% 1-15% 10-40% 30-70% 70-100% Indicative Degree of Project Definition (as % of investment)

Extended Well Test 17

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SLIDE 18

June 2014

Phased Development De-Risks the Full Field Project

18

  • Large areal extent of Bentley requires two drilling

centres

  • First Phase drilled from EWT location
  • Second Phase drilled in southern area of the

field

  • First Phase exploits the northern area utilising

appraisal information

  • Replicates functionality and location of EWT
  • Enables appraisal of Second Phase and

application of lessons learned from First Phase

  • Development plan utilises SIMOPs (Simultaneous

Operations and Production)

  • Production cash flow funds drilling in Second

Phase

  • Drilling experience increases efficiency
  • Two outlying areas outside current 3.5km drilling

reach

  • Bentley Far West and Far North are accessed by

sub-sea completions

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SLIDE 19

June 2014

Base Case Full Field Development Plan

19

First Phase and Full Field Development

FPD with jack-up rig

First Phase Development Plan

  • Permanently manned platform (PUQ), with

20 well slots (18 producers, 2 injector wells)

  • 5 year drilling programme, with jack-up rig

positioned over first phase PUQ

  • Separation system on platform to de-gas

fluids

  • Oil and produced water pumped to

FSO for dehydration – separated produced water re-injected to flanks of aquifer for disposal Second Phase Development Plan

  • Second Phase to start c.5 years after FPD begins
  • 20 slot platform (8 producers, 3 water injectors, 9

spare for further drilling and/or EOR)

  • Development funded by cash flow from FPD

First Phase Development

Second Phase Development

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SLIDE 20

June 2014

Bentley Development Partners: Evolution of First Phase Concept

20

AMEC, Arup and Teekay have joined the development group to undertake pre-FEED/assurance engineering with Xcite and move Bentley through FDP approval and on to long term development

First Phase Development

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SLIDE 21

June 2014

ACE Self-Installing Platform: Proven Design

  • MOU signed with AMEC and ARUP for the design and

development of Arup’s self-installing ACE platform for the Bentley field production facilities

  • Covers all aspects of assurance, engineering,

procurement, construction and installation

  • Self-installing and re-locatable platform – operates as a

moveable offshore production unit

  • Can be fabricated at local yards, almost anywhere in

the world

  • Able to deliver economy and speed of construction

– simple, repetitive fabrication details

  • Limited marine installation vessels required
  • Designed for Decommissioning – rapid and

economical; greater certainty of costs

  • Similar platform installed on Maari field, New Zealand

in 2008 – comparable conditions

21

Arup Concept Elevating (“ACE”) platform

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SLIDE 22

June 2014

Teekay: Sevan Bridge-Linked FSO

22

Sevan bridge-linked FSO

  • MOU signed with Teekay for the supply of a bridge-

linked Sevan FSO facility for the life of the Bentley field

  • Front-end engineering through fabrication, hook-

up and on to production operations and maintenance

  • Proven concept for similar developments
  • Proven UKCS design with a cylindrical hull, utilised for

crude storage

  • High storage capacity
  • Available deck space
  • No turret or swivel
  • No subsea pipeline required
  • Positive motion characteristics – aids dehydration
  • f fluids
  • Simple and efficient construction design
  • 1 million bbl storage allows future field and area

development opportunities

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SLIDE 23

June 2014

Introduction to Xcite Energy Bentley Field – Extended Well Test Bentley Field – Development Plan Financing strategy and Economics Timeline and Investment Highlights Appendix

23

Table of Contents

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SLIDE 24

June 2014

Xcite’s Financing Strategy

24

Bentley Development Group

  • Partners to take/share development risk/reward

to assist alignment and maximise value across the group

  • Reduce upfront cash requirement
  • Asset financing
  • Long-term leases to utilise long-term

production profile revenue

  • Remains complementary to future participation

by farm-in or other partners

  • Intention to sign binding contracts with

development partners once pre-FEED/assurance engineering programmes concluded in 2014, subject to FDP approval

Operator & 100% Licence Holder

Bentley Development Group Bentley Operating Group

Production Operator Reservoir management FSO, moorings & risers Duty holder $$ Leases Services $$ ACE Platform & topsides Engineering & project management Drilling services Operations & maintenance

Technical and Financial Capability

Joint Venture Partner

slide-25
SLIDE 25

June 2014

Long Term Production Profile: 35 years

25

P50 Volume (2P Reserves) of 257 MMstb of oil

  • First Phase wells deliver 67% of the P50 Volume (172 MMstb)
  • FPD Extension wells deliver 7% of the P50 Volume (18 MMstb)
  • Second Phase wells deliver 26% of the P50 Volume (67 MMstb)

10,000 20,000 30,000 40,000 50,000 60,000 70,000

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37

Oil Production Rate (BOPD) Project Year

Oil Production by Phase - P50 Case

SPD Wells FPD Extension Wells FPD wells

  • 5,000

10,000 15,000 20,000 25,000 30,000 35,000 40,000

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24

Oil Production Rate (BOPD) Months of Production

Oil Production for first 24 months - P50

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SLIDE 26

June 2014

Bentley Costs: Reserves Assessment Report, 25 Feb 2014

26

Cost profile (escalated as per NI 51-101)

500 1000 1500 2000 2500 3000 3500 4000 250 500 750 1000

1 2 3 4 5 6 7 8 9 10 Cumulative costs $m Development costs $m Year

Development costs Cumulative costs

6% 2% 6% 13% 3% 6% 59% 4%

FPD Facilities FPD Subsea SPD Facilities FPD Drilling FPD Development Drilling SPD Drilling OPEX Abandonment

Total Cost Breakdown (Unescalated)

81% of Total Costs is OPEX and Drilling

Costs

2P reserves (P50) Escalated (2% p.a.) Unescalated Reserves MMstb 257 257 Capex $3.53bn $3.16bn Opex $7.90bn $5.19bn Decommissioning $0.83bn $0.38bn Total Cost $12.26bn $8.73bn Total Unit Cost $/bbl $47.7 $34.0

FPD Extension Drilling

slide-27
SLIDE 27

June 2014

Assumed Tax Treatment for Xcite Energy and Bentley

27 Based on Brent at $92.3/bbl** with 12% discount

*Tax treatment subject to confirmation by HMRC

Corporation Tax

  • Ring Fence Corporation Tax at 30%
  • Supplementary Charge at 32%
  • USD 380m capital allowance loss pool, as at 31 Dec 2013*
  • USD 360m Supplementary Charge loss pool, as at 31 Dec 2013*
  • Ring Fence Expenditure Supplement of 10% per year over 6 tax accounting periods

Heavy Oil Allowance

  • Bentley Field is eligible for ultra heavy oil allowance of £800 million*
  • Entitlement at 20% per annum over 5 years
  • Relief vs Supplementary Charge only

** McDaniel & Associates, 1st October 2013 back projected Brent forecast

CAPEX 15% OPEX 28% Net Cash Flow 25% RFCT 16% Supplementary Charge 16%

Bentley P50 Full Field Revenue Distribution (2014 RAR Basis, Undiscounted )

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SLIDE 28

June 2014

Introduction to Xcite Energy Bentley Field – Extended Well Test Bentley Field – Development Plan Financing strategy and Economics Timeline and Investment Highlights Appendix

28

Table of Contents

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SLIDE 29

June 2014

2014 Work Plan and Expected Field Development

29

2014 Key work plan

FDP Approval

Platform

  • New Build
  • Early delivery

c.36 months c.24 months

FSO

  • New build
  • Conversion

Drilling Rig

  • New build
  • Existing rig

ACCELERATED NEW BUILD

Front end assurance and engineering to increase the predictability of cost and schedule and reduce technical and execution risks – Emphasis on certainty of delivery

c.36 months c.36 months c.24 months c.24 months Platform & Topsides

  • Cost & Schedule Assessment
  • Platform Assurance Scope
  • Costs Defined
  • Contract Negotiations

FSO

  • Cost & Schedule Assessment
  • Pre FEED
  • Contract Negotiations

Drilling Rig

  • Tender Process
  • Commercial Discussions
  • Contract Negotiations

Drilling / Well Engineering

  • ISP / Well Manager Selection
  • Agree MOU
  • Contract Negotiations

Project Management

  • Contract negotiations
  • FEED preparation
  • Prepare for project sanction
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SLIDE 30

June 2014

Investment Highlights

30

Major UK North Sea Asset USD 250m EWT to De-risk Development Plan Thoroughly Appraised Reservoir Partners and Engineering De-risk Cost and Schedule Robust Economics and Fiscal Incentives Experienced Management Team

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SLIDE 31

June 2014

Introduction to Xcite Energy Bentley Field – Extended Well Test Bentley Field – Development Plan Financing strategy and Economics Timeline and Investment Highlights Appendix

31

Table of Contents

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SLIDE 32

June 2014

32

Phase 1A: Pre-production Flow Test: 9/3b-7(B6) & 7Z(B5)

  • Timing of first water ingress to wellbore and

subsequent rate of water build-up better than expected (ie less water)

  • Ratio of oil to water also better than expected
  • Downhole control valves successfully operated
  • Confirmed large, active aquifer
  • vital for long term pressure support
  • Extensive data gathered
  • significantly improved understanding of oil, gas

and water movement within reservoir

  • c.149,000 barrels of Bentley crude sold to major refiner

in Europe

B6

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SLIDE 33

June 2014

33

Dehydration Times on the FSO