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Zargon Oil & Gas Ltd. January 2014 Corporate Presentation
2
Advisory – Forward-Looking Information
Forward‐Looking Statements ‐ This presentation offers our assessment of Zargon's future plans and operations as at January 8, 2014, 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, 2013 and beyond 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 2014 and beyond, plans to sell un‐strategic assets, the source of funding for our 2014 and beyond capital program including ASP, 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. Discovered Petroleum Initially‐In‐Place (“DPIIP”) is that quantity of petroleum that is estimated, as of a given date, to be contained in known accumulations prior to production. The recoverable portion of discovered petroleum initially in place includes production, reserves, and contingent resources; the remainder is unrecoverable.
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.
3
Zargon Overview(As at January 8, 2014 unless otherwise stated)
Capitalization– Toronto Stock Exchange: Symbols: ZAR; ZAR.DB– Common Shares Outstanding: 30.09 million (basic)– Market Capitalization: $244 million ($8.10 per share) (1)
– Net Debt at September 30, 2013: $118 million
Historical Returns– Returns in dividends and distributions: $339 million ($17.18 per share) since inception– Total Equity Investment since inception: $210 million
Dividend & Yield– Annualized Current Dividend: $0.72 per share– Yield at current share price: 8.9% (1)
Q3 2013 Production (2)
– Equivalent: 7,560 boe/d – Oil: 4,816 bbl/d (64% of production)– Gas: 16.46 mmcf/d
(1) Based on a monthly dividend rate of $0.06/share and using the January 8, 2014 closing share price of $8.10. (2) Prior to the $19.5 million of 2013 Q4 property sales that had been producing 473 boe/d (360 bbl/d and 0.68 mmcf/d).
4
Q1-Q3 2013 Financial Highlights
• Financially Strong– $165.0 million bank line with $43.7 million drawn at September 30, 2013. – $57.5 million Convertible Debenture maturing in 2017, yielding 6% annually.– Net debt at September 30, 2013 (including bank debt, debentures and working capital
deficiency) is $117.6 million; leaving over $100 million of available credit.• Q1‐Q3 2013 Results
– Funds Flow from Operations, $1.55 per basic share.• $46.3 million
– Dividends Paid, $0.54 per basic share ($0.06 per month).• $14.9 million (after DRIP)
– Payout ratio of 32% based on Q1‐Q3 funds flow; (35% before DRIP).
– Commencing September 2013, DRIP program was suspended.• 2013 Capital Program (Spent and Forecast)
– Conventional Spending, $40 million.– Little Bow ASP Spending, $38 million (long term facility construction).– Net Property Dispositions, $35 million.– Net Capital Program, $43 million (Net $36 million spent in Q1‐Q3)
5
Business Plan: Long life oil from exploitation
Oil Exploitation (increasing reservoir oil recovery factors)• Increase oil production, reserves and ultimate recoveries from existing oil pools using
Alkaline Surfactant Polymer (“ASP”) tertiary recovery technology, waterfloods, development drilling and other production optimization methods.
Long‐Life, Low‐Decline Conventional Oil Assets• Long‐life, low‐decline oil exploitation (pressure supported) assets provide free cash flow
that underpins our long term tertiary recovery and dividend strategy.
Tertiary ASP Projects Deliver Long Term Oil Production Growth • Little Bow Phases 1‐4 provide production growth through the end of this decade.
• Protect investor’s underlying asset base with conservative hedging, debt and financing practices.
Dividend Policy
• Zargon is committed to deliver steady and supportable dividends.
• Protect investor’s underlying asset base and dividend stream with conservative hedging, debt and financing practices.
6
Forecast Oil Production TrendsReturn to Growth
• Base oil production is declining at 14% per year and requires approximately half of the annual $35 million capital budget for maintenance and oil exploitation projects.
• Drilling increment assumes 15 net wells per year and consumes the remainder of the annual $35 million conventional budget.
• Remaining property sales are not included in this analysis; but are included in the production history.
0
1,000
2,000
3,000
4,000
5,000
6,000
7,000
Q12013
Q2 Q3 Q4 Q12014
Q2 Q3 Q4 Q12015
Q2 Q3 Q4 Q12016
Q2 Q3 Q4
Oil Prod
uction
(bbl/day)
History Estimate
Drilling IncrementBase Prod. @ 14% decline
ASP Phase 1 &2 increment
Base production and drilling increment are funded by annual $35 million conventional (non ASP)
capital budget.
7
Oil Exploitation Properties(Conventional Oil Exploitation Projects)
8
Conventional Oil Exploitation Projects 2013 Year End Drilling Inventory
Large inventory of oil exploitation opportunities75+Total Available
Elswick, Midale, Weyburn, Ralph, Steelman. Mackobee
Expand & enhance waterflood
Develop Glauconite pool
Increase fluid withdrawal
Multi‐frac horizontals
Project
Horizontal drainage wells in relatively tight reservoirs; pressure support required in some cases
25+Williston Basin
Expand waterflood5Taber South
Implement waterflood concurrently with development10Bellshill Lake Killam
Facility optimization; infills and step‐outs10Bellshill Lake
Will require waterflood re‐implementation, large upside25+Hamilton Lake
CommentsNet
LocationsProperty
Going forward, Zargon plans on drilling approximately 15 high‐graded net oil exploitation wells annually.
2013 Q4 drilling program includes 3 Bellshill Lake, 3 Little Bow and 2.5 net Williston Basin horizontal locations.
8.1 net Williston Basin and Taber drainage type wells were drilled in Q1 – Q3 2013, with 15 net wells now budgeted for 2013.
9
Williston Basin Production Trends & Orientation Map
Estevan
North Dakota
Saskatchewan Manitoba
Haas
Truro
Mackobee Coulee
Frys
Steelman
Ralph
Elswick
Weyburn
Workman
0
500
1,000
1,500
2,000
2,500
3,000
3,500
2007 2008 2009 2010 2011 2012 2013
Prod
ucing Oil Ra
te (b
bl/day)
2013 Additions2012 Additions2011 Additions2010 Additions2009 Additions2008 AdditionsBase Wells
Core Property Group ‐ Williston Basin
Gross W.I. Basis
10
Taber South Sunburst Hz Oil Development & Waterflood
2013 Activities• Drilled 3 additional horizontal wells in Q3
2014 Plan• Drill 3 additional horizontal wells• Convert 2 additional wells to water injection• Increase water handling capacity at 14‐11 battery
0
200
400
600
800
1,000
1,200
2007 2008 2009 2010 2011 2012 2013
Prod
ucing Oil Ra
te (b
bl/day)
2012 Additions2011 Additions2010 Additions2009 Additions2008 AdditionsBase Wells
Core Property Group ‐ Taber Area
Gross W.I. Basis
11
Greater Bellshill Lake Area Production Trends & Orientation Map
Ongoing Activities
• Expanded Bellshill Lake fluid handling capacity is providing 2013 and 2014 pumping upgrade opportunities.
Q4 2013 Activities
• Bellshill Killam pilot waterflood commenced operations.
• 3 vertical wells drilled at Bellshill Lake
0
200
400
600
800
1,000
2007 2008 2009 2010 2011 2012 2013
Prod
ucing Oil Ra
te (b
bl/day)
2012 Additions2011 Additions2010 Additions2009 Additions2008 AdditionsBase Wel ls
Core Property Group ‐ Bellshill Lake Group
2013 Q4 Drilling Program
Bellshill Lake
Bellshill Killam
Pilot WaterfloodCommenced 2013 Q4
12
Hamilton Lake Viking Oil UnitHorizontal Drilling – Large oil resource opportunity
• Waterflood was prematurely suspended in the 1980’s (160 mm bbl DOIIP, 31 °API crude).
• Initially drilled 5 multi‐frac horizontal wells in 2011 and H1 2012 with encouraging results.
• Q4 2012 program was not successful.
• Technical review underway to unlock potential.
Hamilton Lake
Bellshill Lake
Killam Glauconite
0
100
200
300
400
500
2007 2008 2009 2010 2011 2012 2013
Prod
ucing Oil Ra
te (b
bl/day)
2013 Additions2012 Additions2011 Additions2010 Additions2009 Additions2008 AdditionsBase Wells
Core Property Group ‐ Hamilton Lake
Gross W.I. Basis
3 Wells drilled in Q4/2012
Zargon HZ Wells Q4/2012 Horizontal
MultiFrac Test Wells
13
Long-Life, Low-Decline Oil Production Base
0
1,000
2,000
3,000
4,000
5,000
6,000
7,000
2005 2006 2007 2008 2009 2010 2011 2012
Gross W
.I. Oil Prod
uction
Rate ( b
bl/day )
2012 Addi tions2011 Addi tions2010 Addi tions2009 Addi tions2008 Addi tionsBase Production
Zargon Corporate Decline Analysis ‐ Total Oil Production Rate
Data to Dec 31, 2012
Severe BreakupSpring 2011
14.3%Average
37.5%11%2012
28.0%14%2011
14.4%9%2010
21.8%5%2009
20.7%4%2008
5.4%58%Base
2013
Decline Rate
Dec 2012
Contribution
Production
Wedge
• Vintage Zargon operated production plot highlights Zargon’s low‐decline oil production decline of 14%.
• These low declines are forecast to be maintained with $15‐$20 million of non‐drilling oil exploitation capital per year (excludes drilling new wells, but includes waterflood modifications, pumping upgrades, reactivations, etc.).
14
Conventional Assets: Low Corporate Decline and High PDP Reserves
0 10 20 30 40 50
Average Annual Decline Rate (%)
Average 32%
Source: Peters & Co. Limited, Intermediate & Junior Universe (January 6, 2014)
0 20 40 60 80 100
Proved Producing Reserves (% of P+P)
Average 34%
Zargon
15
Alkaline Surfactant Polymer “ASP”: Enhanced Oil Recovery by Tertiary Methods
Process: Dilute concentrations of chemicals (Alkali, Surfactant and Polymer) in water are injected into an existing oil pool to “scrub” out oil that waterflooding alone could not recover.
ObjectiveWash out more oil from an existing reservoir.
•Surfactants (Detergent): Mobilizes trapped oil
•Alkali: Increases effectiveness of the surfactant
•Polymer (Thickener):Thickened water helps sweep oil from the reservoir
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
Water Injection
TrappedOil Droplet Water
RockRock
Mobilized Oil DropletAlkali & SurfactantSolution
16
Little Bow ASPASP Chemical Flooding – Injection Sequence
1 – ASP InjectionA Blend of Alkali,
Surfactant & Polymer mobilizes trapped oil
2 ‐ Polymer “Push”Polymer displaces mobilized oil to producing wells
3‐ Terminal WaterfloodCompletes the Displacement
OIL BANK ASP POLYMER WATER
Little Bow Phase 1 & 2 Injection Schedule
Phase 1 ASP Polymer Waterflood
Phase 2 ASP Polymer
20212017 2018 2019 20202013 2014 2015 2016
17
Existing Canadian ASP Projects
• 9 Canadian ASP Projects in operation
• 4 additional projects have regulatory approval
• Major operators: Husky, CNRL, Cenovus
• Significant implementation in Saskatchewan: favourable EOR royalty treatment
• Technology utilized in Asia since 1980’s
Edmonton
Lethbridge
Calgary
Medicine Hat
Grande Prairie Mooney(Black Pearl)
2011
Coleville (Penn West)
2011Suffield(Cenovus)
2007
Taber South (Husky)2006
Taber (Husky)2008
Grand Forks(CNRL)
Strathmore(Terrex)
Battrum(Hyak Energy)
Fosterton (Husky)2012 Gull Lake
(Husky) 2009
Instow(Talisman)2007/11
Little Bow (Zargon)
Alberta Sask.
Bone Creek (Husky)
Edmonton
Lethbridge
Calgary
Medicine Hat
Grande Prairie Mooney(Black Pearl)
2011
Coleville (Penn West)
2011Suffield(Cenovus)
2007
Taber South (Husky)2006
Taber (Husky)2008
Grand Forks(CNRL)
Strathmore(Terrex)
Battrum(Hyak Energy)
Fosterton (Husky)2012 Gull Lake
(Husky) 2009
Instow(Talisman)2007/11
Little Bow (Zargon)
Alberta Sask.
Bone Creek (Husky)
In Progress
Scheme Approved2013
18
Little Bow Alkaline Surfactant Polymer (“ASP”) ProjectEnhanced Oil Recovery “EOR” Using Proven Technology
Little Bow ASP: Phase 1&2 Development
Little Bow
Alberta 15-18W4
Zargon LandZargon WellsZargon LandZargon Wells
Phase 1 AreaPhase 2 AreaPhase 1 AreaPhase 2 Area
Little Bow Mannville “P” Pool
Little Bow Mannville “I” Pool
• EOR in a mature, southern Alberta Waterflood
• Project Capital: $60 Million (excludes chemical)
– $30 million incurred through Q3 2013 (from 2012/01)
– $18 million remaining to Phase 1 Startup
– $12 million in 2015 (Phase 2)
• Current Little Bow Oil: 400 bbl/d
• First ASP Injection: March 2014
• Zargon Forecast Incremental Oil Rate:2014 Exit: 350 bbl/d2015 Avg: 900 bbl/d2016 Avg: 1,550 bbl/d
• Zargon Forecast Incremental Oil Recovery:5.2 Million Barrels (12% DOIIP)
19
Little Bow ASP FacilityConstruction Progress
June 6, 2013ASP site preparation is underway.Rain and wet conditions slowed progress.
October 2, 2013 Major equipment set.Mechanical/Electrical
proceeding
field of view
December 1, 2013 Mechanical/Electrical 80% Complete
20
2013 Q1 & Q2
• Zargon sanctions construction of Little Bow ASP Facility
• Field pipeline upgrades
• ASP Facility site preparation begins
• Well workover program continues
2013 Q3
• ASP site preparation & piling completed
• Mechanical / Electrical construction begins (ASP and existing oil battery)
• Tank & Equipment deliveries
2013 Q4
• ASP chemical supply contracts in place
• Service wells drilled, well tie‐ins complete
2014 Q1
• ASP facility construction & battery upgrades complete
• Commissioning and Startup
• First ASP injections in March 2014
Little Bow ASPRecent and Upcoming Project Milestones
October 25, 2013
November 12, 2013Photo Courtesy STRIKE Energy Services
21
Little Bow ASPAnalog ASP Project: Husky Taber Mannville “B”
Taber Production History
Sep-12
Sep-11
Sep-10
Sep-09
Sep-08
Sep-07
Sep-06Sep-05
16 % R.F.
16 % R.F.
14.5 % R.F. (Husky Application)
14 % R.F.
14 % R.F.
12 % R.F.(Zargon Base
Case)
12 % R.F.
10 % R.F.
10 % R.F.
8 % R.F.(Zargon PV10 Breakeven)
8 % R.F.
10
100
1,000
10,000
15,000 16,000 17,000 18,000 19,000 20,000 21,000 22,000 23,000 24,000 25,000
Cumulative Oil Production (mbbl)
Oil Production (bbl/d)
1%
10%
100%
1000%
Oil Cut (%
)
Data to July-2013
Oil Cut (%)
Oil Rate, bbl/d
First ASP InjectionMay, 2006
?
?
ERCB DPIIP = 43.1 mmbblASP Recovery Ult. Recovery *
% mmbbl mmbbl8 3.4 20.510 4.3 21.312 5.2 22.214 6.0 23.016 6.9 23.9
* Ultimate Recovery where ASP flood returns to pre‐ASP levels
Taber Mannville “B” ASP Project
• Most mature Canadian ASP Project; Husky Operated
• Same geological setting, oil quality, reservoir size and was at same state of depletion as Zargon’s Little Bow Pool.
• First ASP Injection: 2006
• Incremental recovery is greater than 12%.
Little Bow Mannville “I”and “P” Pools (Zargon)
Taber Mannville “B” Pool (Husky)
22
• Reservoir simulation model used to optimize ASP flood design
• Multiple scenarios:‐ ASP chemical formulation‐ Drilling & workover locations‐ Pattern design
• Optimized case with increased polymer bank predicts 6.5 million barrels incremental ASP oil recovery
• Using a conservative 5.2 million barrels for economics which equates to a 12% incremental recovery factor
Little Bow ASPDevelopment Optimization Study (Phases 1 & 2)
Oil Re
covery
1,276 cases run
Base Waterflood Recovery
ASP Oil Recovery (mbbl)
McDaniel 2012 Year End: 3,900
Zargon 2013 Optimized: 6,500
Zargon 2013 Economics: 5,200
ASP
Oil Re
covery
23
Little Bow ASP Full Cycle EconomicsPhases 1 & 2 (Before Tax as of Jan. 2013)
0
500
1000
1500
2000
2500
2012 2014 2016 2018 2020 2022 2024 2026 2028 2030
BO
PD
Little Bow ASP: Phases 1&2 Production
Base W.F. Phase 1 Phase 2
12.1% Recovery
5.2 mmbbl
Phase 1
Phase 2
Base Waterflood
$ 85/bbl Flat Edmonton Pricing
* Chemical booked as Capital(Chemical booked as Opex: F&D =11.4 $/bbl, Netback = 37.6 $/bbl, Recycle Ratio = 3.3)
** Capital Incurred to September 30, 2013: $30 Million
Phases 1&2
IRR (%) 19.4
PV10 ($ millions) 38.1
F&D ($/bbl)* 26.2
Netback ($/bbl)* 52.4
Recycle Ratio* 2.0
Oil Reserves (mbbl) 5,237
Capital ($ millions) ** 59.6
Chemical ($ millions) 77.8
24
0
5
10
15
20
25
30
$65.00 $75.00 $85.00 $95.00 $105.00 $115.00
IRR
(%)
Edmonton Light ($/bbl)
IRR vs. Price (Before Tax)Little Bow ASP Phases I & 2
Sask. Type EOR Royalty
Little Bow ASP Full Cycle EconomicsPhases 1 & 2 Price Sensitivity: Before Tax IRR
Little Bow Field Realization = Edmonton Light less $17/bbl
Base Price
25
Little Bow ASP Development Expansion: Phases 1-4
* ERCB DOIIP Data
ZAR W.I. (%)
W.I. DOIIP*(mmbbl)
Phases 1 & 2LB “I” Pool 100 31LB “P” Pool 100 8
FollowupU&W Unit 75 21MM Unit 100 5C8C / X8X 81 7
Total 72
Little Bow Phase 1 - 4 Injection Schedule
Phase 1 ASP Polymer WaterfloodPhase 2 ASP Polymer Waterflood
Phase 3 ASP Polymer WaterfloodPhase 4 ASP Polymer
2026 20272013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025
26
Little Bow ASP Full Cycle EconomicsPhases 1-4 (Before Tax as of Jan. 2013)
0
500
1000
1500
2000
2500
3000
2012 2014 2016 2018 2020 2022 2024 2026 2028 2030
BO
PD
ASP Development Forecast - Phases 1-4Base W.F. Phase 1 Phase 2 Phase 3 Phase 4
Zargon W.I. Production
Phases 1&2
12% Recovery
Phases 3&4
11% Recovery
Working Interest Capital and Chemical Costs ($ Millions)
Phases 1&2 Phases 3&4Capital ** 59.6 15.9Chemical 77.8 61.5
** Capital Incurred to September 30, 2013: $30.0 Million
Little Bow ASP: Project Economics
Phases 1&2 Phases 1‐4
IRR (%) 19.4 21.8
PV10 ($ millions) 38.1 67.8
F&D ($/bbl)* 26.2 24.3
Netback ($/bbl)* 52.4 53.7
Recycle Ratio* 2.0 2.2
Reserves (mbbl) 5,237 8,825
* Injectant booked as Capital EDM Flat 85 Pricing Zargon Net W.I.
27
Little Bow ASP Upside Potential
Little Bow ASPUndiscounted Cash Flow
(Net Zargon WI - Before Tax)
-100
0
100
200
300
400
500
600
700
2012 2014 2016 2018 2020 2022 2024 2026 2028 2030
Mill
ions
of D
olla
rs
Little Bow ASP Phases 1&2
Little Bow ASP Upside
Phases 3&4 Development+2% DOIIP Recovery+10$/bbl Edmonton PriceSask EOR Royalty
28
2013 Capital Programs, Dividends and Cash Flows Program Funding Considerations
• 2013 Capital Estimate (November 2013 Update) Conventional Capital Program $40 million ($28 million spent in Q1‐Q3)
ASP Capital Program $38 million ($24 million spent in Q1‐Q3)
Total Capital $78 million
• 2013 Funds Flow after Dividends (based on Q1‐Q3 annualized funds flow)Annualized Q1–Q3 2013 Funds Flow $62 million
Cash Dividends ($20 million)
Available from Funds Flow $42 million
Capital Requirements exceeding Funds Flow $36 million
• 2013 Funding Shortfall provided by Property Sales and Additional Debt Property Sales (Now Closed) $35 million
Additional Debt $1 million
Total Sales and Debt $36 million
Calculated 2013 Year End Debt $115 million
– Calculated 2013 year end debt of $115 million represents 52% of available debenture and bank lines of $222.5 million.
– Increased 2013 debt levels fund the construction of Little Bow ASP infrastructure that will provide low cost reserve and production additions for the next decade.
29
2014 Capital Programs, Dividends and Cash Flows Program Funding Considerations
• 2014 Capital Budget (November 2013 First Look) Conventional Capital Program $35 million
ASP Phase 1 Capital to Complete $ 4 million
ASP Phase 1 Chemical Costs $10 million
Total Capital $49 million
• 2014 Funds Flow after Dividends (Two Examples for Illustration Purposes)Funds Flow Examples $50 million $60 million
Cash Dividends (Drip is suspended) ($22 million) ($22 million)
Available from Funds Flow $28 million $38 million
Capital Requirements exceeding Funds Flow $21 million $11 million
• 2014 Funding Shortfall provided by Property Sales and Additional Debt Property Sales (Proposed) $5 million $5 million
Additional Debt $16 million $6 million
Total Sales and Debt $21 million $11 million
Calculated 2014 Year End Debt $132 million $122 million
– Calculated 2014 year end debt levels represent less 60% of the available debenture and bank lines of $222.5 million.
– In 2015‐17, significant increases in Little Bow ASP cash flow will permit (if desired) debt retirement.
30
Property Disposition Program
2013 Objective: Sell a minimum of $20 million of non‐strategic properties:• Completed property sales:
– $3.5 million in Q1 for Karr, Alberta undeveloped land (1,100 acres undeveloped land and 0.04 mmcf/d).
– $11.6 million in Q2 for Workman & Elswick, Saskatchewan (131 bbl/d).
– $1.4 million in Q3 for Harmattan (and other), Alberta (14 bbl/d).
– $7.5 million ($6.7 million cash) in Q4 for Twining, Provost and Wayne, Alberta properties (120 bbl/d and 0.18 mmcf/d)
– $12.0 million in Q4 for Grand Forks and Peace River properties (240 bbl/d and 0.50 mmcf/d)
• In 2013, Zargon completed the sale of $35 million of properties that had been producing 506 bbl/d and 0.72 mmcf/d.
2014 Objective: Sell a minimum of $5 million of non‐strategic properties:• Additional properties (“other assets”) may be marketed and/or sold in excess
of the $5 million target, provided that the sales improve our organizational focus and reduce our operational footprint.
31
Production Guidance (December 2013 Update)
• Oil and Liquids Guidance:
‐ Q1 2013 5,150 barrels per day (5,113 bbl/d reported) ‐ Q2 2013 4,800 barrels per day (4,930 bb/d reported)‐ Q3 2013 4,650 barrels per day (4,816 bbl/d reported)
‐ Q4 2013 4,550 barrels per day‐ Q1 2014 4,300 barrels per day (incorporates Q4 2013 property sales)
• Natural Gas Guidance:
‐ Q1 2013 15.6 million cubic feet per day (15.2 mmcf/d reported)‐ Q2 2013 15.0 million cubic feet per day (14.8 mmcf/d reported)‐ Q3 2013 14.7 million cubic feet per day (16.5 mmcf/d reported)
‐ Q4 2013 15.0 million cubic feet per day‐ Q1 2014 14.3 million cubic feet per day (incorporates Q4 2013 property sales)
• 2013 ‐ 2014 Cost Assumptions:‐ Operating less than $18.00 per boe (includes transportation costs) ‐ G&A less than $4.50 per boe
32
Net Asset Value Calculations at 2012 Year End
NAV Calculation (Dec 31, 2012)
Proved + Prob. McDaniel Est. (PVBT 10%) $ 473 millionUndeveloped Land $ 22 millionDeduct Est. Net Working Capital & Bank/Debenture Debt ‐ $ 113 million Net Asset Value $ 382 million
Zargon Proved + Prob. Net Asset Value $12.79 per basic share
7.75232323PDP
10.64318409P+PDP
12.79382473Proved & Prob.
8.25246338Total Proved
Net Asset Value ($/basic share)
Net Asset Value
($ million)
McDaniel PVBT 10% ($ million)
Reserve Category
(McDaniel January 1, 2013 price forecast and 29.87 million basic Zargon shares as of December 31, 2012)
2012 Year End Reserves – (Long‐life, low‐decline producing oil)
2P Equivalent Reserves: 31.2 million boe (RLI: 11.0 years)
Oil Reserves:• P+P 23.1 million bbl (RLI: 12.4 years)• P+P Developed Producing 17.3 million bbl (RLI: 9.3 years)• Proved Developed Producing 12.7 million bbl (RLI: 6.9 years)
33
Simplified Estimate of Zargon Break-Up Asset Value
Soldn/a(incl. Q4 Sales)0.72506Impact of Property Sales
$ 469 million15.494,952Grand Total
$ 6071,000 (5 times cf)12.100.74718Bellshill (incl. Killam)
$ 4112.26773Subtotal – Other
$ 68 Nov. 13 Full Cycle Ec. ($38 million) + capital spent thru Q3 13 ($30 million) Little Bow ASP
Asset ValueValuationASP Assets (Incremental)
$ 2815,000Jarrow & Minor11.340Other Gas
$ 1350,000Alberta Plains0267Other Oil (ex. 2013 sales)
Asset Value ($million)
Valuation($/boe/d)Project
Gas Prod.(mmcf/d)
Oil Prod. (bbl/d)Other Assets
$ 36072.053.234,179Subtotal – Core
$ 1643,000 (5 times cf)3.231.06193Hamilton Lake
$ 3647,000 (5 times cf)7.110.97600Little Bow Conventional
$ 6683,000 (5 times cf)13.120.10780Taber South
$ 18293,000 (5 times cf)36.490.361,888Williston Basin (ex. 2013 sales)
Asset Value ($million)
Valuation($/boe/d)
Annual’d Q1‐Q3 2013 Cash Flow
($ million)
Q1‐Q3 13 Gas Prod.(mmcf/d)
Q1‐Q3 13Oil Prod. (bbl/d)
Core ConventionalProperties
Core conventional property value of $360 million less September 30/13 net debt of $118 million leaves $242 million or $8.04 per Zargon share
Analysis ties to Q1 ‐ Q3 2013 production of 7,533 boe/d (4,952 bbl/d and 15.49 mmcf/d)
Little Bow ASP and other assets add $109 million of value, or $3.62/share; resulting in a total break‐up value of $11.66 per share (30.09 million shares)
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Hedging Strategy and 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 70 percent maximum of estimated oil production volumes for the next 12 months. Then
60 percent for the following 12 months and 50 percent for the final 6 month period.
– not to exceed a 30‐month period.
Current Forward Oil Sales:– Q4 2013: 3,000 bbl/d at $97.06 US/bbl (WTI)
– Q1 2014: 3,000 bbl/d at $93.22 US/bbl (WTI)
– Q2 2014: 3,000 bbl/d at $92.61 US/bbl (WTI)
– Q3 2014: 2,200 bbl/d at $90.51 US/bbl (WTI)
and 300 bbl/d at $99.60 Cdn/bbl (WTI)
– Q4 2014: 2,200 bbl/d at $90.51 US/bbl (WTI)
and 300 bbl/d at $99.60 Cdn/bbl (WTI)
– Q1 2015: 400 bbl/d at $91.73 US/bbl (WTI)
Current Forward Natural Gas Sales:
Q1 2014: 6,000 gj/d at $3.38/gj (AECO)
Summer 14: 9,000 gj/d at $3.69/gj(AECO)
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Key Takeaways at Current Share Price(January 8, 2014)
• Zargon is committed to the current $0.06 per share monthly dividend.
– Current 8.9% dividend yield is protected by oil hedges, low payout ratios and a strong balance sheet.
– During the 2013 “ASP heavy spend period”, Zargon bridged the spending gap between cash flows and capital expenditures by property sales.
• The Little Bow ASP project provides significant oil production per share growth for the 2015‐2017 period.
– Little Bow phase 1‐2 production rates are forecast to peak in 2018. Phases 1‐4 peak rates are in 2021. ASP project success could lead to significant follow‐on projects at Little Bow and other Southern Alberta properties.
• Zargon shares represent good value at the current share price of $8.10 per share.
– Investors buy Zargon at a only a very small premium to the proved developed producing year end 2012 “blowdown” net asset value of $7.75 per share (basic).
WWW.ZARGON.CA
Zargon Oil & Gas Ltd. January 2014 Corporate Presentation
