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WWW.ZARGON.CA
Corporate Presentation
Q3 2012 Results
November 7, 2012
Advisory – Forward-Looking Information
Forward-Looking Statements - This presentation offers our assessment of Zargon's future plans and operations as at November 7, 2012, and contains forward-looking statements. Such statements are generally identified by the use of words such as "anticipate", "continue", "estimate", "expect", "forecast", "may", "will", "project", "should", "plan", "intend", "believe" and similar expressions (including the negatives thereof). In particular, this presentation contains forward-looking information as to Zargon’s corporate strategy and business plans, Zargon’s oil exploration project inventory and development plans, Zargon’s dividend policy and the amount of future dividends, future commodity prices, Zargon’s expectation for uses of funds from financing, Zargon’s capital expenditure program and the allocation and the sources of funding thereof, Zargon’s cash flow and dividend model and the assumptions contained therein and the results there from, anticipated payout rates, 2012 production and other guidance and the assumptions contained therein, estimated tax pools, Zargon’s reserve estimates, Zargon’s hedging policies, Zargon’s drilling, development and exploitation plans and projects and the results there from and Zargon’s ASP project plans, capital expenditures, costs and the results therefrom. By their nature, forward-looking statements are subject to numerous risks and uncertainties, some of which are beyond our control, including such as those relating to results of operations and financial condition, general economic conditions, industry conditions, changes in regulatory and taxation regimes, volatility of commodity prices, escalation of operating and capital costs, currency fluctuations, the availability of services, imprecision of reserve estimates, geological, technical, drilling and processing problems, environmental risks, weather, the lack of availability of qualified personnel or management, stock market volatility, the ability to access sufficient capital from internal and external sources and competition from other industry participants for, among other things, capital, services, acquisitions of reserves, undeveloped lands and skilled personnel. Risks are described in more detail in our Annual Information Form, which is available on our website. Forward-looking statements are provided to allow investors to have a greater understanding of our business.
You are cautioned that the assumptions, including, among other things, future oil and natural gas prices; future capital expenditure levels; future production levels; future exchange rates; the cost of developing and expanding our assets; our ability to obtain equipment in a timely manner to carry out development activities; our ability to market our oil and natural gas successfully to current and new customers; the impact of increasing competition; our ability to obtain financing on acceptable terms; and our ability to add production and reserves through our development and acquisition activities used in the preparation of such information, although considered reasonable at the time of preparation, may prove to be imprecise and, as such, undue reliance should not be placed on forward-looking statements. Our actual results, performance, or achievement could differ materially from those expressed in, or implied by, these forward-looking statements. We can give no assurance that any of the events anticipated will transpire or occur, or if any of them do, what benefits we will derive from them. The forward-looking information contained in this presentation is expressly qualified by this cautionary statement. Our policy for updating forward-looking statements is that Zargon disclaims, except as required by law, any intention or obligation to update or revise any forward-looking statements, whether as a result of new information, future events or otherwise.
Barrels of Oil Equivalent - Natural gas is converted to a barrel of oil equivalent (“Boe”) using six thousand cubic feet of gas to one barrel of oil. In certain circumstances, natural gas liquid volumes have been converted to a thousand cubic feet equivalent (“Mcfe”) on the basis of one barrel of natural gas liquids to six thousand cubic feet of gas. Boes and Mcfes may be misleading, particularly if used in isolation. A conversion ratio of one barrel to six thousand cubic feet of natural gas is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead. Given that the value ratio based on the current price of crude oil as compared to natural gas is significantly different from the energy equivalency of 6:1, utilizing a conversion ratio on a 6:1 basis may be misleading as an indication of value.
The estimates of reserves and future net revenue for individual properties may not reflect the same confidence level as estimates of reserves and future net revenue for all properties, due to the effects of aggregation. Estimated reserve values disclosed in this presentation do not represent fair market value.
The aggregate of the exploration and development costs incurred in the most recent financial year and the change during that year in estimated future development costs generally will not reflect total finding and development costs related to reserves additions for that year.
Highlights(As at November 7, 2012 unless otherwise stated)
• Listed on Toronto Stock Exchange: Symbols: ZAR; ZAR.DB
• Common Shares Outstanding: 29.78 million (basic)
• Market Capitalization: $252 million
• Annualized Q4 2012 Dividend: $0.72/share (8.5% yield) (1)
• Q3 2012 DRIP Participation Rate: 13%
• Q3 2012 Oil Production Weighting: 67%
• 2P Reserves (Dec. 31/11): 34.3 million boe (RLI: 10.1 years)
• Net Undev. Land (September 30/12): 361 thousand acres
• Net Debt (September 30/12): $99 million (including debenture)
• Unutilized Bank Lines (September 30/12): $120+ million
(1) Based on a revised 2012 fourth quarter monthly dividend rate of $0.06/share and using the November 6, 2012
closing share price of $8.45.
Financial & Operational Highlights(Quarter ended September 30, 2012)
• Q3 2012 Financial Highlights
• Funds flow – $14.4 million
• Dividends – $7.8 million net of the DRIP
• Capex – $10.4 million, including $1.8 million of ASP capital
• Q3 2012 Production Highlights
– Average Production 7,634 boe/d
• Oil: 5,079 bbl/d (67% of production)
• Gas: 15.33 mmcf/d
• September 30, 2012 Tax Pools of $303 million (> 40% CEE or non capital losses)
– Canadian operations expected to be tax free through at least 2016
• Year End 2011 Reserves (effective December 31, 2011)
– McDaniel Proved and Probable Reserve Estimate (76% developed producing)
• Oil & Liquids: 24.1 mmbbl (11.7 year reserve life index)
• Gas: 61.4 bcf (7.7 year reserve life index)
• Equivalent: 34.3 mmboe (70% oil and liquids)
Business Plan
Oil Exploitation (increasing reservoir oil recovery factors)
• Increase oil production, reserves and ultimate recoveries from existing oil pools through waterfloods, development drilling and other production optimization methods that now include ASP tertiary recovery projects.
• The business plan’s feedstock are underdeveloped oil-in-place assets. We are working on six discrete conventional oil exploitation projects plus the Little Bow ASP tertiary recovery project.
Dividend Policy
• Disciplined cash flow dividend model encourages efficiencies and returns.
• Zargon is committed to deliver steady, but supportable dividends. Dividend payout levels are ultimately targeted to be 35% of cash flow and should not significantly exceed 50% of cash flow for an extended period of time.
Risk Management
• Protect investor’s underlying asset base with conservative hedging, debt and financing practices.
Long-Life, Low-Decline Oil Assets
• Long-life, low-decline oil exploitation (pressure supported) assets provide free cash flow that
underpins our long term dividend strategy.
History of Returns
• Since inception, Zargon has returned $16.34 per share ($315 million) of dividends and distributions to shareholders.
Oil Exploitation Properties (6 Conventional and 1 Tertiary Little Bow ASP Project)
Williston Basin – Two Project Types
Midale Drainage Frobisher Structure
Frys Weyburn
Ralph Steelman
Elswick Mackobee Coulee
Haas
Truro
Conventional Oil Exploitation Projects
Visible Multi-Year Drilling Inventory & Project Opportunities
Large inventory of oil exploitation opportunities130+Total Available
High-Graded Program
Weyburn, Steelman, Mackobee
Elswick, Midale, Weyburn, Ralph, Steelman, Mackobee, Truro, Haas,
Workman
Project
Expand & enhance waterflood
Develop new pool
Increase fluid withdrawal
Multi-frac horizontals
Project
2013-15 high-graded program will promote strong returns (25 net wells per year)
75
Undrained seismically defined horizontal targets15+Frobisher Structure
Horizontal drainage wells in tight reservoirs; pressure support required in some cases
40+Midale Drainage
CommentsNet
LocationsWilliston Basin
Expand waterflood; includes Taber Southeast pool10Taber South
Implement waterflood concurrently with development10Killam Glauconite
Facility optimization; infills and step-outs5Bellshill Lake
Will require waterflood re-implementation, large upside50+Hamilton Lake
CommentsNet
LocationsAlberta Plains
Conventional Project Oil Production and Dividend Sustainability
Oil Production Sustainability (before ASP growth):
Oil production (per share) is expected to be maintained 2013 through 2015 from our existing non-
ASP project inventory, based on the following assumptions:
$50 million annual field capital program; annually 25 wells high-graded from 115+ well
inventory (excluding ASP).
21% corporate average oil production decline rate.
$40,000 per bbl/d capital efficiencies (first year average oil rate).
Dividend Sustainability:
The $0.06 monthly dividend is expected to be maintained through 2015 without property sales or
an increase in net debt, based on the following assumptions:
$85 Cdn. per barrel average FOB Edmonton oil price (2013-15).
$3.85 Cdn. per mmbtu average AECO natural gas price (2013-15).
$20.50 per barrel of oil equivalent average operating, transportation and G&A cost.
An effective royalty rate of 19%, effective interest rate 5.5%, $3 million annual site
reclamations, nominal US cash taxes.
Production Guidance (November 7, 2012 Press Release)
• Oil and liquids:- Q3 2011 5,200 barrels per day (achieved with 5,330 bbl/d) - Q4 2011 5,400 barrels per day (achieved with 5,619 bbl/d) - Q1 2012 5,400 barrels per day (achieved with 5,496 bbl/d)- Q2 2012 5,350 barrels per day after allowing for property sales (achieved with 5,384 bbl/d)- Q3 2012 5,050 barrels per day (achieved with 5,079 bbl/d)
- Q4 2012 revised 5,100 barrels per day (exit rate of 5,400 bbl/d)- 2013 first look 5,400 barrels per day
• Natural gas: - Q3 2011 22.0 million cubic feet per day (achieved with 22.1 mmcf/d)- Q4 2011 21.6 million cubic feet per day (achieved with 22.0 mmcf/d)- Q1 2012 18.6 million cubic feet per day (achieved with 20.0 mmcf/d)- Q2 2012 18.6 million cubic feet per day (missed with 17.4 mmcf/d, due to shut-ins)- Q3 2012 16.5 million cubic feet per day (missed with 15.3 mmcf/d, due to shut-ins)
- Q4 2012 revised 15.5 million cubic feet per day (exit rate of 16.5 mmcf/d)- 2013 first look 15.5 million cubic feet per day
• 2013 Capital Assumptions:- Field capital budget of $50 million focused on six quality non-ASP oil exploitation projects- ASP capital expenditures of $37 million to permit December 2013 ASP project start-up
• 2013 Cost Assumptions:- Operating Costs less than $16 per boe (includes transportation costs) - G&A Costs less than $4.50 per boe (excluding one time items)
Net Asset Value Calculation (2011 Year End)
NAV Calculation (Dec 31, 2011)
Proved + Prob. McDaniel Est. (PVBT 10%) $ 559 million
Undeveloped Land $ 33 millionDeduct Net Working Capital & Bank Debt - $ 109 million Net Asset Value $ 483 million
Zargon Proved + Prob. Net Asset Value $16.45 per share
10.56310386PDP
13.90408484P+PDP
16.45483559Proved & Prob.
11.44336412Total Proved
Net Asset Value
($/share)
Net Asset Value
($ million)
McDaniel PVBT 10%
($ million)Reserve Category
(McDaniel January 1, 2012 price forecast and 29.36 million basic Zargon shares as of December 31, 2011)
Zargon Year End NAV
Peters’ Market Cap Comparison to NAV
(50)
0
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250
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400
Pre
miu
m (
Dis
cou
nt)
to
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V (
%)
Companies
Peters & Co. Limited, Intermediate & Junior Universe (November 5, 2012)
Zargon
Hedging Strategy Current Hedges
• Zargon uses hedges to help fund dividends and capital programs during periods of lower commodity prices. Our policies allow for the forward sale of:
– up to a 60 percent maximum of estimated production volumes
– up to a maximum 30-month period
• Current Forward Oil Sales:
– Q4 2012: 2,500 bbl/d at $99.92 US/bbl (WTI)
– H1 2013: 2,350 bbl/d at $99.57 US/bbl (WTI)
– H2 2013: 1,800 bbl/d at $98.20 US/bbl (WTI)
– H1 2014: 400 bbl/d at $97.05 US/bbl (WTI)
Key Takeaways at Current Share Price (November 6, 2012)
• Zargon oil exploitation business provides considerable upside.
– Zargon has simplified its business to focus on the exploitation of seven profitable oil projects.
• Hamilton Lake, Killam, Bellshill Lake, Taber, Williston Basin (Midale, Frobisher) provide a multi-year inventory of profitable oil exploitation projects.
– These six exploitation projects are economic to pursue at considerably lower oil prices.
• The Little Bow ASP project provides long-life reserves for Zargon.
– Little Bow success will lead to significant follow-on projects at Little Bow and other Zargon properties.
• Zargon shares represent good value at the current share price.
– Investors buy Zargon at a 20% discount to the proved developed producing year end 2011 “blowdown” net asset value of $10.56 per share (basic). No value is ascribed to a rich inventory of oil exploitation projects (neither booked undeveloped reserves or “unbookedpotential” reserves.)
• Zargon provides a long dated call option on future oil prices and pays an 8+ percent dividend in the interim.
– Downside is protected by a strong balance sheet and WTI oil hedges.
– Low-decline oil production (particularly with ASP) underpins the dividend for many years.
WWW.ZARGON.CA
Appendix A: Six Conventional Oil Exploitation Projects
Oil Exploitation Project Review
• Six active project areas in three exploitation teams
– Alberta Plains South
• Taber Sunburst Waterflood Exploitation project
– Alberta Plains North
• Bellshill Lake Development & Optimization
• Hamilton Lake Viking project
• Killam Glauconite Project
– Williston Basin
• Frobisher Horizontal development
• Midale Drainage
• Development of type curves for each project
– Derived from all Zargon 2010 and 2011 drilling results with actual well performance to October 2012
• Cash flow analysis based on $85 CDN per barrel FOB Edmonton par price and historical field differentials
Zargon Conventional Oil Exploitation Projects
Evaluations Based on Actual Zargon Field Results
$ 16,000$ 8.002.82254551$ 1,105 $ 4005 / 0Bellshill Lake (HZ Re-Entry)
$ 21,000$ 11.002.245364110$ 2,450$ 1,10010 / 1Taber Sunburst
$ 44,000$ 20.500.16416261$ 286 $ 1,80050+ / 0Hamilton Lake Viking [2]
$ 27,000$ 12.901.37528675$ 1,919$ 1,400Optimized Target Well .
$ 50,000$ 16.500.51274258$ 680 $ 1,35010 / 3Killam Glauconite - Primary
$ 42,000$ 15.900.87406075$ 1,450$ 1,680Target Waterflood Well [3]
40+ / 2
15+ /1
Pot’l/
Booked
Wells
$ 52,800$ 17.601.14245275$ 1,493$ 1,320Williston Basin Midale
$ 21,500$ 15.002.025811384$ 2,495$ 1,240Williston Basin Frobisher
Production [1]
Addition
Efficiency
($/bbl/d)
F&D
($/BOE)
P.I.R.
@ 10%
6 Month
Oil Rate
(bbl/d)
30 Day
Oil Rate
(bbl/d)
Oil
Reserves
(Mbbl)
PV@10%
($M) [4]
CAPEX
($M)Project Name
Notes: [1] based on mid-year rate
[2] cost & productivity upside
[3] waterflood capital of $325M included
[4] using base oil price of $85.00 Cdn at Edmonton
Alberta Plains North Orientation Map
Jarrow
Bellshill Lake
Hamilton Lake
Killam Glauc
StettlerProvost
Camrose
Wainwright
Alberta Plains NorthViking Oil Drilling Activity (2007 to 2012)
• In the greater Hamilton Lake
area since 2007, nearly 300
multi-frac horizontal wells have
been drilled targeting the Viking
formation
• In the last two years, Zargon has
drilled five longer reach Viking
horizontal wells using ball and
seat technology. Results were
varied, but on average the wells
will recover 60 mbbl of oil
reserves
• In Q4 2012, Zargon drilled four
Viking horizontal wells using
monobore and frac sleeves
technologyHamilton Lake
Jarrow
Bellshill Lake
Killam Glauc
Viking Oil Wells drilled since 2007
Hamilton Lake Viking Oil UnitHorizontal Drilling – 3 Well Program in Q4
Q4/2012 Horizontal MultiFrac Test WellsZargon HZ Wells
3 Wells planned for Q4/2012
31 API gravity sweet crude
Developed in the 1960’s
Waterflood was prematurely suspended in the 1980’s
High reservoir pressure due to over injection
Drilled 5 multi-frac horizontal wells
Hamilton Lake Viking Oil UnitProduction History of the Viking Unit
• The Hamilton Lake Oil Unit waterflood was prematurely suspended in the 1980’s with less than a 10 percent reservoir recovery
• Our reservoir modeling suggests that significant reserves additional can be recovered with multi-frac horizontal well technology
0
1,000
2,000
3,000
4,000
5,000
0 5,000 10,000 15,000 20,000
Cumulative Oil Produced ( Mbbl )
Oil
Pro
du
ctio
n R
ate
( b
bl/
da
y )
0%
10%
20%
30%
40%
50%
60%
70%
80%
90%
100%
Oil
Cu
t (
% )
Viking C
Viking B
15.9434222Jul-12
15.8926167Dec-11
15.862861Dec-10
Cum Oil
(MMbbl)
Oil Cut
(%)
Oil Rate
(bbl/d)
Hamilton Lake Viking Oil UnitProduction History Including Recent HZ Wells
10
100
1,000
10,000
1965 1970 1975 1980 1985 1990 1995 2000 2005 2010
Oil
Pro
du
ctio
n R
ate
( b
bl/
da
y )
Production restored to early 1990's levels
Hamilton Lake Viking - Productivity Implications Horizontal Well Orientation, Fracture Optimization
• Horizontal well with a NE to SW orientation
‒ fracture stimulation follows approximately along
the length of the horizontal section and has
resulted in reduced reservoir contact with lower
than expected productivity.
• Horizontal well with a NW to SE orientation
‒ fracture stimulation is expected perpendicular to
the length of the horizontal section which is
expected to improve initial productivity and also
ultimate recovery.
Water Injector
Dominant Induced Fracture Direction
Waterflood swept area
Partially Swept Oil
Current Zargon HZ Oil Wells
Q3/2012 Proposed HZ Wells
Legend
N
Wat
er in
ject
ion fr
actu
re o
rienta
tion
Water channels between
injectors & producers
• Production history shows that water injection has
trended NE to SW between injectors, leading to early
water breakthrough in vertical oil producers, resulting
in low overall recovery.
Hamilton Lake Viking Oil UnitHistoric Well Performance & Type Curve
Well Production History Dataset Average Type Curve Target Well
Hamilton Lake - Horizontal MultiFrac Wells
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10
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-01
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-02
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-02
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-03
Year-Month on Production
Fie
ld E
stim
ate
d D
aily
Oil
Pro
du
ctio
n (
bb
l/d
ay
)
Target Well
-500
0
500
1,000
1,500
2,000
2,500
3,000
60 65 70 75 80 85 90 95 100 105 110
2013 Oil Price (FOB Edmonton) ( $Cdn/bbl )
Be
fore
Ta
x D
CF
@ 1
0%
( $
M )
Hamilton Lake Viking - Primary Depletion Type Curve Evaluation
Hamilton Lake Viking Oil Unit Historical Results under Three Pricing Scenarios
6230 day rate (bbl/d)
61Reserves - Oil (Mbbl)
165- Gas (MMcf)
44,000Efficiency ($/bbl/d)
20.50F&D ($/BOE)
0.16P.I.R. @ 10%
4.2Payout (yrs)
16%IRR (%)
416 Month Rate (bbl/d)
88Total (Mboe)
$ 286PV10 ($M)
$ 1,800CAPEX ($M)
Analysis Using Base Pricing
2013 “Base Price”
Edm. Light $85.00/bbl
Field Price $79.00/bbl
• Target well based on improved costs and slightly higher rates
• Hamilton Lake holds a large oil exploitation resource with significant potential
Target Well
Ba
se P
rice
Target Well: IP30 90 bbl/d, 75 Mbbl oil, $1.4 MM capital
OPEX ($/bbl) $ 13.50
Target OPEX ($/bbl) $ 9.00
H2H Pool
Bellshill LakeStable Oil Production from Exploitation
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1,000
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lls
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)
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il R
ate
( b
bl/
d )
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10,000
100,000
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id R
ate
( b
bl/
d )
Optimization &
Infill Drilling
Bellshill Optimization
- Battery expansion (complete)
- Leduc water disposal well (complete)
- Doubling of battery fluid capacity
2012 Q3 - Q4 Program
- 3 hz re-entry candidates, 1 vertical location
Bellshill LakeHistoric Well Performance & Type Curve
Bellshill Lake - Development & Optimization
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Year-Month on Production
Fie
ld E
stim
ate
d D
ail
y O
il P
rod
uct
ion
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bl/
da
y )
Well Production History Dataset Average Type Curve
Bellshill Lake Historical Results under Three Pricing Scenarios
4530 day rate ( bbl/d)
16,000Efficiency ($/bbl/d)
8.00F&D ($/BOE)
2.82P.I.R. @ 10%
0.8Payout (yrs)
500%IRR (%)
256 Month Rate (bbl/d)
51.0Reserves - Oil (Mbbl)
$ 1,105PV10 ($M)
$ 400CAPEX ($M)
Analysis Using Base Pricing
0
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1,000
1,500
2,000
60 65 70 75 80 85 90 95 100 105 110
2013 Oil Price (FOB Edmonton) ( $Cdn/bbl )
Be
fore
Ta
x D
CF
@ 1
0%
( $
M )
Bellshill Lake - Well ReEntry Type Curve Evaluation
Ba
se P
rice
OPEX ($/bbl) $ 9.20
2013 “Base Price”
Edm. Light $85.00/bbl
Field Price $74.80/bbl
• Bellshill Lake has good economic returns with some further re-entry drilling potential
Killam Glauconite Oil ProjectWaterflood Project Development Candidate
26 Degree API sweet crude
Zargon drilled 7 Hz producers
100% WI in four sections
Significant waterflood upside
1
10
100
1,000
2005 2006 2007 2008 2009 2010 2011 2012
Oil
Ra
te (
bb
l/d
)
Future Development Oil Wells
Future Infill Water Injection Wells
Killam Glauconite Waterflood CandidatePilot Waterflood Project - Phase 1 & 2 Scope
• Pilot waterflood application
was approved by ERCB
review in Sept, 2012
• Water injection expected to
commence by March 2013
06-15 WSW &
Battery
13-15 InjPhase 1 Scope
Phase 2 Scope
Killam Glauconite Oil Project Historic Well Performance & Type Curve
Well Production History Dataset Average Type Curve Target Well
Killam Glauconite - Oil Project
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-04
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Year-Month on Production
Fie
ld E
stim
ate
d D
ail
y O
il P
rod
uct
ion
( b
bl/
day
)
Primary Depletion Performance
Target Waterflood Well
Killam Glauconite Oil Project Historical Results under Three Pricing Scenarios
4230 day rate ( bbl/d)
58.0Reserves - Oil (Mbbl)
140- Gas (MMcf)
50,000Efficiency ($/bbl/d)
16.50F&D ($/BOE)
0.51P.I.R. @ 10%
2.5Payout (yrs)
34%IRR (%)
276 Month Rate (bbl/d)
82Total (Mboe)
$ 680PV10 ($M)
$ 1,350CAPEX ($M)
Analysis Using Base Pricing
OPEX ($/bbl) $ 16.85
2013 “Base Price”
Edm. Light $85.00/bbl
Field Price $73.70/bbl
• Waterflood potential is the key to value in the Killam Glauconite project
• Proceeding with a pilot project to test the waterflood
-500
0
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1,000
1,500
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2,500
60 65 70 75 80 85 90 95 100 105 110
2013 Oil Price (FOB Edmonton) ( $Cdn/bbl )
Be
fore
Ta
x D
CF
@ 1
0%
( $
M )
Killam Glauconite Project - Primary Depletion Type Curve Evaluation
Ba
se P
rice
Target Waterflood Well
Target Well: IP30 60 bbl/d, 75 Mbbl oil, $1.68 MM capital
Alberta Plains South Orientation Map
Little Bow
Taber
Grand ForksRetlaw
Lethbridge
Taber
Enchant
Vauxhall
Taber South Sunburst Hz Oil Development
2012 Activities
• Expand Horizontal Waterflood
‒ Improve injectivity of existing wells
‒ Convert 02/06-01 hz to injection
• Recently finished drilling 2 hz. oil wells
Forecast 2013 Activities
• Drill 2-3 more horizontal wells
• Convert an additional well to water injection
• Increase water handling capacity at 14-11 battery
Future Activities
• Drill 5-7 more wells
• connect batteries 14-11 & 15-36 to further optimize waterflood, and expand injector count as required
Production Contribution by Drilling Program Date
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600
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1,000
2007 2008 2009 2010 2011 2012
Oil
Ra
te (
bb
l/d
ay
)
Base 2008 2009 2010 Q1 2011 Q3 2011
1 well converted to water injection
2 wells converted
Data to Jul 31, 2012
Hz Oil Well
Hz Water Injector
Q4/2012 Hz Well
Injector Conversion
Phase 2
Waterflood
Phase 1
Waterflood
Sunburst Pool
Outline
Taber Sunburst Waterflood Project Historic Well Performance & Type Curve
Taber Sunburst - Horizontal Oil Exploitation Project
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-01
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-03
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-05
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Year-Month on Production
Fie
ld E
stim
ate
d D
ail
y O
il R
ate
( b
bl/
day
)
Well Production History Dataset Average Type Curve
Taber South Historical Results under Three Pricing Scenarios
6430 day rate ( bbl/d)
21,000Efficiency ($/bbl/d)
11.00F&D ($/BOE)
2.24P.I.R. @ 10%
0.9Payout (yrs)
153%IRR (%)
536 Month Rate (bbl/d)
100.0Reserves - Oil (Mbbl)
$ 2,450PV10 ($M)
$ 1,100CAPEX ($M)
Analysis Using Base Pricing
0
500
1,000
1,500
2,000
2,500
3,000
3,500
4,000
60 65 70 75 80 85 90 95 100 105 110
2013 Oil Price (FOB Edmonton) ( $Cdn/bbl )
Be
fore
Ta
x D
CF
@ 1
0%
( $
M )
Taber Sunburst Oil Project - Type Curve Evaluation
Ba
se P
rice
OPEX ($/bbl) $ 8.00
2013 “Base Price”
Edm. Light $85.00/bbl
Field Price $70.50/bbl
• The recently implemented waterflood is having a positive impact on production
• Further drilling and expansion of the waterflood area are warranted
Williston Basin Orientation Map
Estevan
North Dakota
Saskatchewan Manitoba
Haas
Truro
Mackobee Coulee
Frys
Steelman
Ralph
Elswick
Weyburn
Workman
Steelman (Frobisher Zone) Production Growth from Recent Drilling Programs
Production Contribution by Drilling Program Date
10
100
1,000
2007 2008 2009 2010 2011 2012
Oil
Ra
te (
bb
l/d
)
Pre 2008 2008 2009 2010 2011
Cumulative Oil Production to May 2012 of 945 Mbbl
Gross Area Production Additions
Frobisher ProgramHistoric Well Performance & Type Curve
Williston Basin - 2010 and 2011 Frobisher Drilling Results
1
10
100
1,000
00
-01
00
-02
00
-03
00
-04
00
-05
00
-06
00
-07
00
-08
00
-09
00
-10
00
-11
00
-12
01
-01
01
-02
01
-03
01
-04
01
-05
01
-06
01
-07
01
-08
01
-09
01
-10
01
-11
01
-12
02
-01
02
-02
02
-03
02
-04
02
-05
02
-06
02
-07
02
-08
02
-09
02
-10
02
-11
02
-12
Year-Month on Production
Fie
ld E
stim
ate
d D
ail
y O
il P
rod
uct
ion
( b
bl/
da
y )
Well Production History Dataset Average Type Curve
Frobisher ProgramHistorical Results under Three Pricing Scenarios
11330 day rate ( bbl/d)
21,500Efficiency ($/bbl/d)
15.00F&D ($/BOE)
2.02P.I.R. @ 10%
0.5Payout (yrs)
388%IRR (%)
586 Month Rate (bbl/d)
84.0Reserves – Oil (Mbbl)
$ 2,495PV10 ($M)
$ 1,240CAPEX ($M)
Analysis Using Base Pricing
0
500
1,000
1,500
2,000
2,500
3,000
3,500
4,000
60 65 70 75 80 85 90 95 100 105 110
2013 Oil Price (FOB Edmonton) ( $Cdn/bbl )
Be
fore
Ta
x D
CF
@ 1
0%
( $
M )
Williston Basin Structural Project (Frobisher) Type Curve
Ba
se P
rice OPEX ($/bbl) $ 9.85
2013 “Base Price”
Edm. Light $85.00/bbl
Field Price $79.60/bbl
• Frobisher wells are prolific with high initial decline rates, but eventually stabilizing
• Economic returns are excellent and the wells have a long producing life
Midale ProgramHistoric Well Performance & Type Curve
Well Production History Dataset Average Type Curve
Williston Basin - 2010 & 2011 Midale Drilling Program
1
10
100
1,000
00
-01
00
-01
00
-03
00
-04
00
-05
00
-06
00
-07
00
-08
00
-09
00
-10
00
-11
00
-12
01
-01
01
-02
01
-03
01
-04
01
-05
01
-06
01
-07
01
-08
01
-09
01
-10
01
-11
01
-12
Year-Month on Production
Fie
ld E
stim
ate
d D
ail
y O
il P
rod
uct
ion
( b
b/d
l )
Midale Program Historical Results under Three Pricing Scenarios
5230 day rate ( bbl/d)
53,000Efficiency ($/bbl/d)
17.60F&D ($/BOE)
1.14P.I.R. @ 10%
2.4Payout (yrs)
45%IRR (%)
246 Month Rate (bbl/d)
75.0Reserves – Oil (Mbbl)
$ 1,493PV10 ($M)
$ 1,320CAPEX ($M)
Analysis Using Base Pricing
0
500
1,000
1,500
2,000
2,500
3,000
3,500
60 65 70 75 80 85 90 95 100 105 110
2013 Oil Price (FOB Edmonton) ( $Cdn/bbl )
Be
fore
Ta
x D
CF
@ 1
0%
( $
M )
Williston Basin Drainage Project (Midale) Type Curve
Ba
se P
rice OPEX ($/bbl) $ 7.00
2013 “Base Price”
Edm. Light $85.00/bbl
Field Price $74.70/bbl
• Midale wells have moderate initial productivity but also low initial decline rates
• Economic returns are excellent and the wells have a long producing life
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Appendix B: Little Bow Alkaline Surfactant Polymer (“ASP”) Tertiary Recovery Project
ASP Chemical Flooding Recovers Bypassed Oil
ASP floods utilize:• Surfactants (detergent) to mobilize
oil that waterflooding alone leaves trapped in the reservoir
• Alkali added to increase the efficiency of the injected surfactants
“Recovers more oil from reservoir rock contacted by chemical”
• Polymer thickens the injected water and improves reservoir sweep
“Contact more reservoir rock”
Polymer “thickens” the injected fluid to increase the volume of reservoir contacted.
Injector Producer
WaterWater
Injector Producer
PolymerSolution
IncreasedContactVolume
PolymerSolution
IncreasedContactVolume
a) Water Injection b) Polymer Injection
RockRock
a) Water Injection:More than half of oil is “trapped”
b) Alkali / SurfactantMobilizes trapped oil
Alkali and Surfactant act together to mobilize oil trapped in the reservoir. The injected fluids must contact the trapped oil to be effective.
Water Injection
TrappedOil
Water
RockRock
Mobilized Oil
Alkali & SurfactantSolution
ASP Chemical Flooding – Injection Schedule
Injection Sequence
1) ASP: A blend of Alkali, Surfactant and Polymer mobilizes trapped oil
2) Polymer “Push”: Polymer solution displaces mobilized oil to producing wells
3) Terminal Waterflood: Completes the displacement.
Canadian ASP Projects
Battrum (Hyak Energy)
Little Bow (Zargon)
Taber (Husky)
Strathmore (Terrex)
Suffield (Cenovus)
Mooney (Black Pearl Resources)
Instow (Talisman)
Edmonton
Lethbridge
Calgary
Medicine Hat
Grande Prairie
Grand Forks
(CNRL)
Gull Lake ( Husky)
Fosterton (Husky)
Coleville (Penn West)
In Progress
Scheme Approved
100
1,000
10,000
100,000
1964 1968 1972 1976 1980 1984 1988 1992 1996 2000 2004 2008 2012
Oil P
rod
uc
tio
n &
Wa
ter
Inje
cti
on
(b
pd
)
0%
1%
10%
100%
Oil C
ut (%
)
Data to July 2012
Injection
Oil Cut
Oil Rate
Southern AlbertaASP Project Orientation (Zargon Little Bow & Husky Taber Analogy)
Lethbridge
Taber Mannville ‘B’
Pool (Husky)
Little Bow Upper Mannville
‘I’ and “P” Pool (Zargon)
6 miles
Taber
Lethbridge
Taber Mannville ‘B’
Pool (Husky)
Little Bow Upper Mannville
‘I’ and “P” Pool (Zargon)
6 miles
Taber
Zargon Little Bow Production History
Husky ASP Flood
Initiated
Taber Production History
100
1,000
10,000
100,000
1972 1976 1980 1984 1988 1992 1996 2000 2004 2008 2012
Oil P
rod
ucti
on
& W
ate
r In
jec
tio
n (b
pd
)
0%
1%
10%
100%
Oil C
ut (%
)
Data to July 2012
Injection
Oil Cut
Oil Rate
Little Bow Mannville “I” & “P” And Taber Mannville “B” Similar
Reservoir Characteristics
• Potential ASP project reservoirs are limited - based on reservoir and fluid properties
• Taber Mannville “B” and Little Bow are close analogs
Taber Little Bow ASP Screening
Lithology Sandstone Sandstone Sandstone �API Oil Gravity 19 21 > 15 �Mean Depth (ft) 3,226 3,555 < 6000 �
Average Permeability (mD) 1,000 900 > 100 �Reservoir Temperature ( °F) 88 91 < 180 �
Viscosity (cp) 40 21 < 200 �Successful Waterflood Yes Yes Yes �
Average Porosity (%) 25 23 > 15 �Original Pressure (psia) 1,134 1,615
Net Pay (ft) 23 37
Initial Water Saturation (%) 22 21
Little Bow Mannville “I” and “P” Pools
Zargon Land
Zargon Wells
“MM” Unit
“C8C / X8X” Pool
“U&W” Unit
Little Bow “I” Pool
Little Bow “P” Pool
Alberta
Little Bow
Alberta
Little Bow
100
1,000
10,000
100,000
2000 2002 2004 2006 2008 2010 2012
Oil
Pro
du
cti
on
(b
pd
)
0.1%
1.0%
10.0%
100.0%
Oil C
ut (%
)
Data to July 2012
Oil Cut
Oil Rate
Initial Oil: 300 bpd
Peak Oil: 1814 bpd
Peak Oil Cut: 13%
Initial Oil Cut: 2%
ASP Injection Polymer Injection
Taber Mannville B – Continued Strong Performance
Taber Mannville “B” - ASP Flood Reserves
1%
10%
100%
20% 25% 30% 35% 40% 45% 50% 55%
Cumulative Oil Produced ( % DPIIP )
Oil
Cu
t (%
)
Data to July 2012
Oil Cut
ERCB Assigned DPIIP: 43.1 MMbbl
Terminal
WaterfloodASP Polymer
12% DPIIPBase Waterflood
Decline
ASP Flood
Decline
Little Bow ASP Development: Phase 1&2
• Phased development approach for Little Bow and future pools
• ASP facilities designed for multi-phase development
• Little Bow developed in two overlapping
ASP/Polymer cycles
Zargon Land
Zargon Wells
Zargon Land
Zargon Wells
Zargon Land
Zargon Wells
Phase 1 Area
Phase 2 Area
Phase 1 Area
Phase 2 Area
Little Bow ASP: Phase 1&2 Development Areas
Little Bow Phases 1 and 2 Injection Schedule
Phase 1 ASP Polymer Waterflood
Phase 2 ASP Polymer Waterflood
2013 2014 2015 2016 20212017 2018 2019 2020
Little Bow ASP Oil Recovery: Phase 1&2
• Incremental oil rate peaks in excess of 1,500 bopd in 2017
• McDaniel Year End 2011 Evaluation
– 3.7 mmbbl Oil
– 4.15 mmboe
– Probable Undeveloped
Little Bow ASP Production: Phases 1 & 2
0
200
400
600
800
1000
1200
1400
1600
1800
2000
2012 2014 2016 2018 2020 2022 2024 2026 2028 2030
BO
PD
Base Phase 1 Phase 2
12% Recovery
4.4 mmbbl
Phase 1
Phase 2
Base Waterflood
Little Bow ASP Facility Site
• Travers gas plant acquisition completed July 2012
• ASP Facility relocated to open area south of Gas Plant
• Pipeline relocation and aggregation no longer required
• Plot Plan Optimization
– More compact footprint
– Phase 2 expansion considerations
Travers Gas Plant16-31 Battery
Zargon Land
Zargon Wells
Zargon Land
Zargon Wells
Zargon Land
Zargon Wells
Phase 1 Area
Phase 2 Area
Phase 1 Area
Phase 2 Area
Little Bow ASP: Phase 1&2 Development Areas
Future Little Bow ASP Facility
Little Bow ASPProcess Overview
Water
Softening
Water
De-oiling
Injection
ASP Fluid
Blending
Little Bow ASPCapital Costs (non-Chemical)
• “As spent” dollars
• Unit cost: 13.36 $/bbl Oil
Phase 1 Phase 2 Total
($MM) ($MM) ($MM)
ASP Facility 32.3 1.7 34.0
Battery 9.2 3.2 12.4
Pipelines 1.5 3.2 4.7
Water Disposal/Source 1.5 0.0 1.5
Subsurface/Surface 3.0 4.2 7.2
47.5 12.3 59.8
Little Bow ASP - Phase 1&2
Capital & Chemical Costs and BTax NCF(As Spent $ - Annual)
-40
-30
-20
-10
0
10
20
30
40
2012 2014 2016 2018 2020 2022 2024 2026 2028 2030$ M
illio
ns
-120
-90
-60
-30
0
30
60
90
120
Cu
mu
lativ
e ($
Millio
ns
)
Capital+Chem NCF Cumulative NCF
Phases 1&2: Expenditure & Net Cash Flow
Field pricing based on Edmonton $85/bbl Flat Pricing
BTax ROR vs. Price
0
5
10
15
20
25
30
$65.00 $75.00 $85.00 $95.00 $105.00 $115.00
Edmonton Light ($/bbl)
RO
R (
%)
Little Bow ASP Phases I & 2
Phases 1&2 Price Sensitivity: Before Tax ROR
Ba
se P
rice
• Little Bow Field Realization = Edmonton Light Less 17 $/bbl
• For ROR = 10%: Field realization = 68 – 17 = 51 $/bbl
Phases 1&2 Recovery Sensitivity: Before Tax RORUpside Cases
BTax ROR vs. Oil Recovery
10
12
14
16
18
20
22
8 9 10 11 12 13 14 15 16
Recovery (% DPIIP)
RO
R (
%)
Little Bow ASP Phases I & 2
Ba
se R
.F.
Increment from Edmonton
price increase to $95/bbl
Increment from EOR
Royalty reform
• Incremental Before Tax PV10 from:
‒ Base price increase is $15MM
‒ EOR royalty could be $20MM
Field pricing based on Edmonton $85/bbl Flat Pricing
ASP Followup Development
Phases 1 & 2
8100LB “P” Pool
Followup
781C8C / X8X
1968U&W Unit
70Total
5100MM Unit
31100LB “I” Pool
W.I. DPIIP*
(mmbbl)ZAR
W.I. (%)
* ERCB DPIIP Data
Zargon LandZargon WellsZargon LandZargon WellsZargon LandZargon WellsZargon LandZargon Wells
ASP Phase 1 & 2
“MM” Unit
“U&W” Unit
“C8C/X8X” Pool
15-018W415-019W4
14-018W414-019W4
Zargon LandZargon WellsZargon LandZargon WellsZargon LandZargon WellsZargon LandZargon Wells
ASP Phase 1 & 2
“MM” Unit
“U&W” Unit
“C8C/X8X” Pool
15-018W415-019W4
14-018W414-019W4
Little Bow Phases 1 - 4 Injection Schedule
Phase 1 ASP Polymer Waterflood
Phase 2 ASP Polymer Waterflood
Phase 3 ASP Polymer Waterflood
Phase 4 ASP Polymer
2021 2022 20232017 2018 2019 20202013 2014 2015 2016
Project Economics - Phases 1 - 4
ASP Development Forecast - Phase 1-4
0
500
1000
1500
2000
2500
2012 2014 2016 2018 2020 2022 2024 2026 2028 2030
BO
PD
Base Phase 1 Phase 2 Phase 3 Phase 4
Zargon W.I. Production
Phase 1&2
12% Recovery
Phase 3&4
11% Recovery
Phase 3&4 Capital Costs (Zargon Net W.I.)
Phase 3 Phase 4 Total
($MM) ($MM) ($MM)Battery 4.9 0.0 4.9
Pipelines 2.4 1.7 4.1
Subsurface 3.2 3.4 6.610.5 5.1 15.6
ASP Chemical 19.7 20.5 40.2
Total 30.2 25.6 55.8
Little Bow ASP Upside Potential
Little Bow ASP
Undiscounted Cash Flow (Net Zargon WI - Before Tax)
-100
-50
0
50
100
150
200
250
300
350
400
450
500
2012 2014 2016 2018 2020 2022 2024 2026 2028 2030
Mil
lio
ns
of
Do
lla
rs
Little Bow ASP Phase 1&2
Little Bow ASP Upside
Phases 3&4 Development
+2% DPIIP Recovery
+10$/bbl Edmonton Price
EOR Royalty Reform
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Corporate Presentation
Q3 2012 Results
November 7, 2012