1. business and industrial
2. energy
3. oil

November 2014
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
$ 4.19 (as of November 6, 2014)
Market Capitalization
CDN$1.09 Billion
Liquidity
2 Million shares/day (3 months average)
Research Coverage
13 analysts provide coverage
Ownership by Region
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
• Drilling 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
Strong Record of
Production Growth
232 Million barrels 2P
5.4 Billion barrels OIIP
Q4 2014 average production to date
22,000 bopd
Attractive Well
Economics
Horizontal wells NPV $3.0 Million,
Payout in 13 months
Robust Pricing
> $30 netbacks at $80 Brent
Strong Cash Flow
$85 Million in Q3 2014
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 and
Beyond
Forecasting steady annual growth of 10% to 15%, through continuation of the primary development
program, implementation of secondary recovery, and diligent planning for tertiary recovery.
Average Historical Patos-Marinza Production
Production (bopd)
20,000
16,000
12,000
8,000
4,000
1939
1944
1949
1954
1959
1964
1969
Albpetrol
1974
1979
Bankers
1984
AAP
1989
1994
1999
2004
2009
6
2014
Engineered Momentum
Execute Drilling
Program
• 10 – 15% annual production growth
• Expanded to 6 drilling rigs in Q1 2014
• Drill 150 - 170 horizontal wells in 2014
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
• Expand port capacity to improve contracts
Validate Polymer and
Water Flood
• 18 polymer and 3 water flood patterns underway
• Initial production results are performing in line or
exceeding expectations of 5 – 10% incremental recovery
in the limited pilot areas tested to date
• 13 wells converted to polymer injection in 2014
7
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
to
date
2006
2007
2008
2009
2010
2011
2012
2013
2014
8
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
$3.0 Million
< 1 year (~30,000 bbls)
75 - 80%
9
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
$29,950/bopd
10
Reserves Allocation
Depth: 2000 m
Core Area
2013
Oil initially in place (OIIP)
1.7 Bbbls
Recovery to date
131 Mbbls
Recovered by Bankers
29.8 Mbbls (23%)
Remaining booked
160 Mbbls
Total Recovery using Primary Techniques
17% (current 8%)
Upside in Water Flood and Polymer Flood Recovery
Southern & Periphery Area
2013
Oil initially in place (OIIP)
0.7 Bbbls
Recovery to date
22 Mbbls
Recovered by Bankers
0.5 Mbbls (2%)
Remaining booked
60 Mbbls
Total Recovery using Primary Techniques
12% (current 3%)
Upside in Primary, Polymer Flood and Thermal Recovery
Depth: 0 m
11
Reservoir Characteristics &
Development Strategy
Composite Type Section
Primary Development
I
Horizontal Drilling & Reactivation of Existing
Wells
Polymer Flood – Viscosity 500cP to 2500cP
•
Additional Core & Data Collection for Tertiary
•
Tertiary - Viscosity > 2500cP
•
Sandstone Reservoir
•
Up to 300m Gross & 200m Net Oil Pay
•
Porosity 25 to 30%, Permeability 100 to
2,000md
•
API 5° to 20°, Live Oil Viscosity 50cP to
80,000cP
Marinza
Well Depth: 300 to 2,000m
I
•
8-20 API
Reservoir Description
50 m
•
Driza
Water Flood – Viscosity 50cP to 500cP
I
•
Primary Horizontal Drilling
Reduced Space Pattern Drilling
Water and Polymer Flood 8–20 API
•
Gorani
Secondary and Tertiary Development
Tertiary Development 5–10 API
•
12
Development Program
Historical Drilling Program by Zone
2014 locations in red
Gorani
Lower Driza
Upper Driza
•
519 horizontal wells drilled to the
end of Q3 2014 (includes 23
lateral redrills)
•
Pad drilling across 15 zones
•
995 future horizontal well
locations at ~200m lateral
spacing (2P Reserves Case
January 1, 2014 effective date)
•
Downspacing to 100m for
incremental primary recovery
and completion of secondary
recovery patterns
Marinza & Bubullima
13
Netbacks
Netback ($/bbl)
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
$60
$50
$40
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
$30
$20
$10
$0
2009
2010
2011
2012
2013
14
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
On-going Initiatives
(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
Targeting a $2-3/bbl savings over the next 2 years
15
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
•25,000
bopd
treatment
capacity,
•modular
&
scalable
ARMO Refinery
• 10,000 bopd refining
capacity
• under new management
• currently offline
• Port Expansion: In final negotiations
with PIA for to dredge port to allow for
40,000 T cargo vessels. Management
considering future export volumes.
• Domestic Refining: resumed sales
volumes to ARMO in Q3 to test
domestic refining capabilities for a
period of 6 months to determine if
there is a possible future domestic
market. No volumes have been
committed beyond 2014.
• 2015 sales contracts: Currently in
negotiations for the 2015 sales
contracts.
Highway
• 30,000 bopd
transport capability
• new 4-lane highway
• Future pipeline
route planning
Export
Partners
REP
SOL
Spain
TOTAL
France
ENI
Italy
API
Italy
MOCOH
Trader
16
Water and Polymer Injection
Water flood Implementation
• 1st Waterflood pattern initiated early Q2 2013
• 3 injection wells in the Upper Marinza (M0) formation
at the end of Q3 2014
• Initial patterns in 10 – 700 cP viscosity range
Polymer Flood Pilot
• 1st Polymer pattern initiated late Q1 2013
• 18 injection wells in 3 different zones at the Q3 2014,
distributed evenly in the D5, D4 and D3
• Initial patterns in viscosity range of 700 – 1,600 cP
• H2 2014 patterns testing 650 – 850 cP viscocity range
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
17
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
18
EOR Pattern Performance
M0 Water Flood Pattern (10-250 cP)
D5 Polymer Patterns (700 – 1,400 cP)
250
250
200
Oil Rate (bbl/d)
Oil Rate (bbl/d)
200
150
100
100
50
50
0
0
0
10
20
30
Time from Start of Injection (months)
0
40
D4 Polymer Patterns (800 – 1,600 cP)
250
10
20
30
Time from Start of Injection (months)
40
D3 Polymer Patterns (800 – 1,100 cP)
250
200
200
Oil Rate (bbl/d)
Oil Rate (bbl/d)
150
150
100
50
150
100
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
40
Time from Start of Injection (months)
+17% Recovery
Data as of Aug. 31, 2014
19
Incremental EOR Production
Oct-14
Oct-14
350 bopd
Jul-14
Jul-14
Apr-14
Jan-14
Oct-13
Conversion
* Data as of August 31, 2014
Apr-14
Jan-14
Oct-14
310 bopd
Jul-14
Apr-14
Jan-14
Oct-13
Jul-13
Pattern Results by Zone
Primary Type Curve by Zone Well
D3 Polymer Flood
Oct-13
Oct-14
Jul-14
Apr-14
Jan-14
Oct-13
Jul-13
Apr-13
D4 Polymer Flood
Apr-13
500
450
400
350
300
250
200
150
100
50
0
Jan-13
Oil Rate (bopd)
0
Jan-13
100
Jul-13
200
Jul-13
300
Apr-13
400
Apr-13
370 bopd
Oil Rate (bopd)
500
Jan-13
500
450
400
350
300
250
200
150
100
50
0
600
D5 Polymer Flood
Jan-13
Oil Rate (bopd)
500
450
400
350
300
250
200
150
100
50
0
Oil Rate (bopd)
M0 Water Flood
700
20
Water and Polymer Flood
Early Stage Results
• We are strongly encouraged by the results and will
continue to expand the water and polymer flood pilots to
test additional areas of the field and reservoir zones with
13 conversions in 2014 and estimated 25 conversions in
2015
• All 3 polymer and 1 water flood pilots have achieved
proper injectivity and have seen no early break-through
• Pattern performance for all pilots are in line with or
better than simulation expectations with respect to offset
producer response
21
The Science Behind Steam
2000 m
Core Flood & Simulation
• Conducting core testing and
analysis in the south for
integration with mapping to
identify thermal expansion areas
0m
•
Future tertiary development would
likely require cyclic steam
technology, injecting steam into the
reservoir for a period of time to heat
the oil, then producing the oil
•
Commercial tertiary development of
the field would require a source of
natural gas
Potential thermal zone
Testing areas
22
Enhancing the Value of Patos-Marinza
Natural Gas for Tertiary Development
• Block “F”
•
Bankers elected to progress into Second Exploration Period of license in
November 2013; have acquired 3D seismic on the block in 2014
• Trans Adriatic Pipeline (TAP)
•
Selected by the Shah Deniz Consortium to bring natural gas from the
Caspian region to Europe
•
Pipeline route crosses directly through the Patos-Marinza oil field and will
bring a source of natural gas to the area
•
Joint Venture comprised of BP, SOCAR, Statoil, Total, E.ON
•
Commissioning planned for 2019 with capacity of 10 bcm/year
Light Oil Exploration to offset Diluent Usage
•
•
Kuçova
•
Similar development plan to Patos-Marinza, except with 12-17° API liquids
•
Drilling 2 horizontal wells in 2014 with more development to follow
Bubullima
• Deeper light oil pool north of Patos-Marinza, within the concession
• First test well indicates meaningful flow rates, further development requires
Sour Treating Facilities, currently being designed
23
2014 Capital Program
Fully Funded $313 million budget
Primary Development
•
•
•
•
•
6 drilling rigs, 150 – 170 wells to be drilled in 2014
Workover and reactivation program
Gathering and flow line systems
Additional storage tanks
3 water disposal wells
Secondary and Tertiary Development
•
•
•
Drilling, Reactivations
and Workovers
Water Control
Base Capital
$22 Million
Capital allocated for up to 14 wells to be converted for
water and polymer injection
Associated facilities with water and polymer flood
activities
5 core wells in Southwestern Patos-Marinza for the
propose of evaluating thermal potential
New Ventures
•
•
$285 Million
Drilling 2 Kuçova horizontal wells
Acquire 20 km2 3D Seismic on Block “F”
Conversions &
Drilling
Facilities
$6 Million
Drilling
Other
24
Strong Balance Sheet
LIQUIDITY at September 30, 2014
Working capital of $190 Million; CASH of $88 Million
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
300
300
250
250
200
200
150
150
100
100
50
50
0
2009
2010
2011
Actual up to Q3
2012
2013
Estimate
Financial hedge (Put Option) in place
(Millions of US$)
350
2014
0
2009
2010
2011
Actual up to Q3
2014 - 6,000 bopd at $80/bbl Dated Brent
2012
2013
2014
Estimate
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
850 bopd of Pre-existing Albpetrol Production “PEP” 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
Chairman, Porto Energy Corp. Previously Executive VP, Exploration & Development, Bankers
Petroleum Ltd. and Vice President, Exploration of Rally 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
Jennings Capital
Mark Heim
Cormark Securities
Garett Ursu
Industrial Alliance
Securities
Amin Haque
Credit Suisse
David Phung
RBC Capital Markets Al Stanton
FirstEnergy
Darren Engels
Scotiabank
Gavin Wylie
GMP
David Beddis
TD Newcrest
Jamie
Somerville
Goldman Sachs
Ruth Brooker
Wood & Company
Robert Rethy
Haywood Securities Darrell Bishop
31