January 2015 Corporate Presentation TSX | AIM: BNK Disclaimer Certain information contained herein respecting the Company, the Company's properties or anticipated financial results or performance of the Company or its properties constitutes forward-looking information. Such forward-looking information, including but not limited to, statements with respect to anticipated rates of production, the estimated costs and timing of the Company's planned work program and reserves determination involve many known and unknown risks, uncertainties and other factors which may cause the actual costs and results of the Company and its operations to be materially different from estimated costs or results expressed or implied by such forward-looking statements. Such factors include, but are not limited to, risks related to international operations including political risks, general risks associated with petroleum operations (such as commodity prices, production delays, production costs, exchange rate fluctuations and environmental costs and risks) and risks associated with equipment procurement and equipment failure. Although the Company has attempted to take into account important factors that could cause actual costs or results to differ materially, there may be other factors that cause costs of the Company's program or results not to be as anticipated, estimated or intended. There can be no assurance that such statements will prove to be accurate as actual results and future events could differ materially from those anticipated in such statements. The forward-looking statements contained herein are made as of the date hereof and the Company undertakes no obligations to update or revise any forward-looking statements or information, whether as a result of new information, future events or otherwise. Accordingly, readers should not place undue reliance on forwardlooking information. 2 Company Overview Bankers Petroleum Ltd. is an international E&P company with operational focus in Albania. TSX – Toronto | AIM – London Stock Exchange Symbol: BNK Total Shares 261 Million (281 Million fully diluted) Share Price $ 2.66 (as of January 29, 2015) Market Capitalization CDN $694 Million Liquidity 2 Million shares/day (3 months average) Research Coverage 14 analysts provide coverage Ownership by Region Canada United Kingdom Australia & NZ Asia United States France Other Europe 3 Asset Overview- Albania Patos-Marinza Oilfield • Largest onshore oilfield in Europe • 100% W.I. and operatorship • 220 Million Barrels – 2P Reserves Kuçova Oilfield • 100% W.I. and operatorship • 12 Million Barrels 2P Reserves • Drilled first horizontal well in 2014 Block F Exploration Acreage • Prospective for natural gas CORE FOCUS AREA ACCESSIBLE TO REGIONAL AND INTERNATIONAL MARKETS 4 Investment Highlights Large Primary Reserves 232 Million barrels 2P 5.4 Billion barrels OIIP Strong Record of Production Growth 2014 annual average production 20,687 bopd Robust Pricing $25 cash margin at $50 Brent Strong Balance Sheet 2015 capital program fully-funded with cash flow and cash resources Attractive Fiscal Regime Albania’s largest producer and foreign investor 5 History of Patos-Marinza 1928 – 1990 1990 Patos-Marinza was first discovered by APOC (Anglo Persian Oil Co.) and developed in stages by Russians and Albanians. Fall of Communism in Albania 1995 – 2004 AAP (Anglo Albanian Petroleum, a partnership between Premier Oil , IFC, OMV, and Albpetrol) signed the original concession, but due to weak oil price environment and punitive contract terms, the Company relinquished the block in early 2004. 2004 - 2007 Bankers Petroleum renegotiated and signed a new concession agreement in July 2004 and grew production from 400 to 6,000 bopd through reactivation of legacy vertical wells. 2008 – 2012 Growth of production from 6,000 to 15,000 bopd through development and delineation drilling of new horizontal wells across 11 different reservoir zones and multiple areas of the field. 2013 - 2014 Two year average of 17.5% production growth in through a strategy focused on primary development program, validating secondary recovery techniques, and reducing costs through operational efficiencies in the field Average Historical Patos-Marinza Production 20,000 (bopd) 16,000 12,000 8,000 4,000 - 1939 1944 1949 1954 1959 1964 1969 1974 Albpetrol Bankers 1979 AAP 1984 1989 1994 1999 2004 2009 6 2014 Engineered Resilience Execute Drilling Program • 2 drilling rigs, 60 wells new horizontal wells • Operational flexibility to adjust pace of drilling with oil prices Expand Product Margin • Optimize treating process and sourcing to reduce diluent costs • Install flow lines to reduce infield trucking • Reduce energy costs through alternate fuel use Accelerate Polymer Flood Program • 19 polymer and 4 water flood patterns to end of 2014 • Initial production results are performing in line or exceeding expectations • Up to 20 polymer conversions anticipated in 2015 7 2015 Capital Program of $153 M Primary Development • 2 drilling rigs, 60 horizontal wells to be drilled • Gathering and flow line systems • 1 water disposal well • Large programs for electrification, pump upsizing, and other OPEX reductions $125 Million Drilling EOR Development • Capital allocated for up to 20 wells to be converted for water and polymer injection • Associated facilities • Shifting from pilot to development phase of the EOR project Workovers Facilities Disposal $28 Million Facilities Well Conversions 8 Others 2015 Sales Contracts Total cash realization equivalent of 82% Dated Brent • Inclusive of domestic and export contracts as well as existing hedge Export Market • 55% of 2015 volumes will be sold to the export market • All export volumes committed to contracts at 79-80% of Dated Brent • Counterparties in the Mediterranean, the United States Domestic Market • 45% of 2015 volumes will be sold to domestic refiners • Agreement for 74% of Dated Brent FOB Vlora equivalent, plus a fixed $28/metric-ton or approximately $4.45/bbl recovery against a delinquent accounts receivable balance ($15.4 million to be recovered in 2015) • ~ $2.90 saving in Royalty and Sales and Transportation savings in comparison to export sales 9 Cash Margin Equivalent $70.00 Hedge AR Netback S&T OPEX Royalties $60.00 $/bbl $50.00 $40.00 $4.35 $11.46 $4.89 $11.49 $30.00 $6.63 $20.00 $7.76 $2.09 $10.00 $6.84 $10.75 $2.09 $5.44 $11.53 $7.04 $13.75 $2.09 $5.98 $11.57 $7.24 $16.74 $2.09 $6.52 $11.61 $7.44 $7.07 $11.64 $7.64 $7.61 $11.68 $7.84 $19.73 $22.72 $25.71 $12.22 $10.69 $9.16 $7.64 $2.09 $6.11 $2.09 $4.58 $2.09 $3.05 $40.00 $45.00 $50.00 $55.00 $60.00 $65.00 $70.00 Cash Realization $44.51 $46.75 $49.01 $51.26 $53.50 $55.74 $57.98 % Brent Equivalent 111% 104% 98% 93% 89% 86% 83% Realized Price $30.20 $33.97 $37.76 $41.53 $45.30 $49.07 $52.84 % Brent 75.5% 75.5% 75.5% 75.5% 75.5% 75.5% 75.5% $22.07 $23.53 $25.00 $26.47 $27.93 $29.39 $30.85 $Brent Price ($/bbl) Cash Margin 10 Strong Balance Sheet LIQUIDITY at September 30, 2014 Working capital of $190 Million; CASH of $88 Million (estimated cash of $73 Million at December 31, 2014) Credit Facilities Facility Utilized Available $20 Million $0 Million $20 Million IFC / EBRD* $204 Million $104 Million $100 Million Total $224 Million $104 Million $120 Million Raiffeisen Bank * Inclusive of $80 Million pursuant to 2013 2P reserves assessment. CAPEX Cash Flow (Millions of US$) 350 (Millions of US$) 350 300 300 250 250 200 200 150 150 100 100 50 50 0 0 2009 2010 2011 Actual up to Q3 2012 2013 Estimate Financial hedge (Put Option) in place 2014 2009 2010 2011 2012 2013 Actual up to Q3 Estimate 2015 - 6,000 bopd at $80/bbl Dated Brent 2014 11 Netbacks 2012 2013 Q3 2014 Brent $111.67 $108.66 $101.93 Sales Price (% of Brent) $79.73 (71% ) $85.39 (79%) $78.55 (77%) Royalties $14.46 $14.22 $11.36 Transportation $2.38 $2.44 $2.34 Energy $3.83 $2.88 $2.25 Well Servicing $3.32 $2.77 $2.34 Other $4.85 $5.25 $5.74 OPEX $14.38 $13.34 $12.67 Net Diluent 7.79 $7.29 $6.78 Transportation & Terminal Fees 2.83 $2.81 $1.96 Sales & Transport $10.62 $10.10 $8.74 Netbacks $40.27 $47.73 $45.78 Netback ($/bbl) $60 $50 $40 $30 $20 $10 $0 2009 2010 2011 2012 2013 12 2014 Q3 Cost Structure Improvements Category Diluent Energy Q1 2013 $7.12 $3.32 Q3 2014 $6.78 $2.25 Cost Savings Potential Savings $0.34 $0.50 $1.00 • • • • Produce lighter oil Proactive tank turnarounds Optimize workovers Optimize treating chemicals $1.07 $0.50 $1.00 • • • • Consolidate generators Gas gathering system Field electrification Flowline • • • • Continuous rod Tubing rotators PC pump design Optimize well construction • Pipeline and flowline infrastructure • Improve in-field trucking patterns (2-3 years) Well Servicing $4.11 $2.34 $1.77 $0.50 $0.75 In-field Transportation $2.48 $2.34 $0.14 $0.65 $0.90 $3.32 Total Savings ($6.25 excluding taxes) On-going Initiatives • $2.93 of additional savings were neutralized by excise and C&C taxes that were introduced in 2014 • Taxes are fully cost recoverable and act as a future tax deduction 13 Off-take Infrastructure • Export Pipeline: 2 year right of way on export pipeline route to the Vlore Port Terminal from Fier Hub. Management currently considering size of pipeline. CTF • 10,000 bopd refining capacity • under new management • currently offline • Port Expansion: Expansion plans and permits in place for future port expansion. In final negotiations with PIA for to dredge port to allow for 40,000 T cargo vessels. Highway • 30,000 bopd transport capability • new 4-lane highway • Future pipeline route planning • Domestic Refining: resumed sales volumes to ARMO in Q3 2014 to allow for increase operational flexibility Export Partners REPSOL Spain OMV Austria •25,000 bopd treatment capacity, •modular & scalable ARMO Refinery ENI Italy API Italy MOCOH Trader 14 Patos-Marinza Average Quarterly Production 22,500 20,000 17,500 Horizontal Wells: 429 Production (bopd) 15,000 12,500 10,000 7,500 Vertical Wells: 107 5,000 2,500 0 Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 2006 2007 2008 2009 2010 2011 2012 2013 2014 15 Horizontal Well Performance Average Horizontal Well Profile 120 480 Oil Rate 3P recovery case 2P recovery case 1P recovery case Well Count Oil Rate (CD, bopd) 80 400 320 60 240 40 160 20 80 0 0 0 20 40 Months On Production Recoverable Reserves 1st Month IP 12 – 18 Month Decline After 18- 20 months 80 100 Well Economics *2P Recovery Case Parameters *2P Recovery Case Well Costs 60 $1.2 Million 150,000 bbls 90 - 100 bopd ~50% 15% NPV 10% Before Tax Payout IRR After Tax At December 31, 2013 $3.0 Million < 1 year (~30,000 bbls) 75 - 80% 16 Producing Well Count 100 Reserves Value / Metrics December 31, 2013 Reserves 147 Mbbls 232 Mbbls 144 Mbbls 220 Mbbls 3 Mbbls 12 Mbbls 22 years 35 years Net Present Value at 10% After Tax (Millions) $1,216 $2,240 Per Share ($CDN) $5.27 $9.72 $20.45/bbl $12.08/bbl $2,161 $2,309 Number of Hz wells 984 995 Recycle ratio @ $100 Brent 2.1x 3.5x Patos-Marinza Kuçova Reserve Life Index Exchange rate as of Feb. 20, 2014 Finding and development costs Future capital (Millions) Drilling Capital Efficiency 2014 Including all associated facilities and infrastructure costs $29,950/bopd 17 Reserves Allocation Depth: 2000 m Core Area 2013 Oil initially in place (OIIP) 1.7 Bbbls Recovery to date 131 Mbbls Recovered by Bankers 29.8 Mbbls (23%) Remaining booked 160 Mbbls Total Recovery using Primary Techniques 17% (current 8%) Upside in Water Flood and Polymer Flood Recovery Southern & Periphery Area 2013 Oil initially in place (OIIP) 0.7 Bbbls Recovery to date 22 Mbbls Recovered by Bankers 0.5 Mbbls (2%) Remaining booked 60 Mbbls Total Recovery using Primary Techniques 12% (current 3%) Upside in Primary, Polymer Flood and Thermal Recovery Depth: 0 m 18 Reservoir Characteristics & Development Strategy Composite Type Section Primary Development I Horizontal Drilling & Reactivation of Existing Wells Polymer Flood – Viscosity 500cP to 2500cP • Additional Core & Data Collection for Tertiary • Tertiary - Viscosity > 2500cP • Sandstone Reservoir • Up to 300m Gross & 200m Net Oil Pay • Porosity 25 to 30%, Permeability 100 to 2,000md • API 5° to 20°, Live Oil Viscosity 50cP to 80,000cP Marinza Well Depth: 300 to 2,000m I • 8-20 API Reservoir Description 50 m • Driza Water Flood – Viscosity 50cP to 500cP I • Primary Horizontal Drilling Reduced Space Pattern Drilling Water and Polymer Flood 8–20 API • Gorani Secondary and Tertiary Development Tertiary Development 5–10 API • 19 Development Program Historical Drilling Program by Zone 2014 locations in red Gorani Lower Driza Upper Driza • 558 horizontal wells drilled to the end of Q4 2014 (includes 24 lateral redrills) • Pad drilling across 15 zones • 995 future horizontal well locations at ~200m lateral spacing (2P Reserves Case January 1, 2014 effective date) • Downspacing to 100m for incremental primary recovery and completion of secondary recovery patterns Marinza & Bubullima 20 Water and Polymer Injection Water flood Implementation • 1st Waterflood pattern initiated early Q2 2013 • 4 injection wells in the Upper Marinza (M0) formation at the end of 2014 • Patterns are in 10 – 700 cP viscosity range Polymer Flood Pilot • 1st Polymer pattern initiated late Q1 2013 • 19 injection wells in 3 different zones at the end of 2014, distributed evenly in the D5, D4 and D3 • Patterns are in viscosity range of 700 – 1,600 cP Core Flood & Simulation • Core flood tests to obtain fluid and rock property data for modeling water flood and polymer flood performance • Numerical modeling to history match initial pattern results and predict future performance 21 Illustration Type Curve – Early Stage 250 Oil rate peak response Oil rate plateau for 4-8 months (increasing water production rate during period) Fully Supported Producer Oil Rate (bopd) 200 1 well converted at ~12 months (~ 50 bopd) 150 100 Oil rate decline established 50 Response expected in 1 year 0 0 12 24 36 Time (Months) 48 60 72 (2 x 1/2) Injector & (1) Producer Pair 22 EOR Pattern Performance M0 Water Flood Pattern (10-150 cP) Oil Rate (bbl/d) 300 Oil Rate (bbl/d) D5 Polymer Patterns (700-1400 cP) 250 350 250 200 150 100 200 150 100 50 50 0 0 0 10 20 30 Time from Start of Injection (months) 0 40 20 30 40 Time from Start of Injection (months) D3 Polymer Patterns (800-1100 cP) D4 Polymer Patterns (800-1600 cP) 250 250 200 Oil Rate (bbl/d) 200 Oil Rate (bbl/d) 10 150 100 150 100 50 50 0 0 0 10 20 30 Time from Start of Injection (months) Pattern Results by Zone Primary Type curve +5% Recovery +12% Recovery 40 0 10 20 30 Time from Start of Injection (months) +17% Recovery * Data as of Nov. 30, 2014 40 23 Pattern Results by Zone Primary Type Curve by Zone Well 100 0 300 250 200 57 bopd Conversion * Data as of Nov. 30, 2014 24 Jan-15 Oct-14 Jul-14 Apr-14 Jan-14 Oct-13 339 bopd 500 450 400 350 300 250 200 150 100 50 0 Jan-15 200 Oct-14 350 Jul-14 500 Apr-14 400 Jan-14 600 Jul-13 M0 Water Flood Oct-13 0 Jul-13 100 Apr-13 200 Jan-13 300 Oil Rate (bopd) 700 Apr-13 300 Oil Rate (bopd) 400 353 bopd 500 Jan-15 800 Jan-13 400 348 bopd Oil Rate (bopd) 600 Jan-15 Oct-14 Jul-14 Apr-14 Jan-14 Oct-13 Jul-13 Apr-13 Jan-13 D4 Polymer Flood Oct-14 Jul-14 Apr-14 Jan-14 Oct-13 Jul-13 Apr-13 Jan-13 Oil Rate (bopd) Incremental EOR Production D5 Polymer Flood D3 Polymer Flood 150 100 50 0 Water and Polymer Flood Acceleration • Strongly encouraged by the results to date Bankers will increase its spending on EOR by 27% and double the number of conversions compared to 2014 • 20 estimated conversions in 2015 • Pattern performance for all pilots are in line with or better than simulation expectations with respect to offset producer response 25 Fiscal Terms Term • Royalties • • • – – • 25 year term to 2029 with multiple 5 year extensions Blended average 17% decreasing to 14% over the next 5 years 10% Government Mineral Tax 1% Albpetrol Share of Production “ASP” 3% after 1x cost recovery 5% after 2x cost recovery 775 bopd of Pre-existing Albpetrol Production “PEP” decreased from 850 bopd at beginning of 2014. Balance is declining at 15% per annum. Excise Tax • 37 Lek/ Liter on all refined products imported into Albania Value Added Tax • Fully Reimbursed within 3 months 100% Cost Recovery • CAPEX, OPEX, G&A and Government tax 50% Profit Tax on Free Cash Flow • After full cost recovery 26 Surface Infrastructure Optimization Lease Construction Well Pad Tie ins, Treating, Testing, Sour Handling, Control & Automation Production Gathering System Satellite Treating Facility (Pad D/H, Sat 3) Water Disposal System Central Treating Facility (CTF) Disposal sites Tanker (increasing load size from 20,000 to 40,000MT) Storage at PIA (increasing storage & loading capacity) WTP Disposal Pipeline Sales Oil Transfer Fier Hub Storage 27 Health, Safety, Environment & Community Relations Environmental •Clean-up and remediation •Meeting International standards Previous Albpetrol well Health & Safety •Creating safe work environments •Trained and competent workforce Health, Safety, Environment & Community Relations Economic Development •Agricultural Programs •Supporting Sustainable business Re-activated well Stakeholder Engagement •Building Capacity •Reducing Impacts •Occupational Training LIABILITY MANAGEMENT BY CONTINUOUS CLEAN-UP 28 Management Team David French Rob Carss President & CEO VP, HSSE Doug Urch Leonidha Çobo Executive VP Finance & CFO VP & General Director Albania Suneel Gupta Mark Hodgson Executive VP & COO VP, Business Development Bayne Assmus Craig Nardone VP, Production & Operations VP, Exploration & Development Bruce Beveridge VP, Engineering 29 Board of Directors Robert Cross, Chairman Private investor; over 20 years experience financing companies in the resource sector and is on the board of several Canadian energy and mining companies Abdel (Abby) Badwi, Vice Chairman Retired from President and CEO of Bankers Petroleum in April 2013; more than 40 years experience in the exploration, development and production of international oil and gas fields. Previously President and CEO of Rally Energy Corp. Eric Brown President, E.M.Brown Consulting Corporation. Previously held the position of Regional Managing Partner for Meyers Norris Penny, LLP General Wesley Clark (ret.) CEO, Wesley Clark & Associates since 2004; Chairman of Rodman & Renshaw from February 2006. Senior Fellow, UCLA’s Burkle Centre for International Relations David French President and CEO, Bankers Petroleum since April 2013; 23 years experience in the development and production of oil and gas fields in North America and overseas. Previously held the position of VP, Business Development, of Apache Corporation Jonathan Harris Business Consultant, Genet Consulting Ltd since February 2005; Chief Operating Officer and Director of Anglo-African Minerals Plc from May 2009 to February 2012; Previously COO of Tribeka Ltd and director of Eastern Platinum Ltd. London, UK based Phil Knoll President, Corridor Resources from October 2010 to September 2014; Executive Vice President, Duke Energy from March 2002 to July 2005; Director of Corridor Resources, AltaGas Utility Group; former Director of Rally Energy Ian McMurtrie Previously Executive VP, Exploration & Development, Bankers Petroleum Ltd. and Vice President, Exploration of Rally Energy Corp. Former Chairman, Porto Energy Corp. John Zaozirny Vice-Chairman, Canaccord Financial Inc.; Previously Counsel, McCarthy Tetrault LLP. Currently on the Board of Directors for numerous Canadian oil and gas companies 30 Analyst Coverage Canaccord Genuity Christopher Brown Haywood Securities Darrell Bishop CIBC Dave Popowich Mackie Research Mark Heim Cormark Securities Garett Ursu Industrial Alliance Securities Amin Haque Credit Suisse David Phung RBC Capital Markets Al Stanton Dundee Capital Markets David Dudlyke Scotiabank Gavin Wylie FirstEnergy Darren Engels TD Securities Jamie Somerville GMP David Beddis Wood & Company Robert Rethy 31
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