Zargon Oil & Gas Ltd. March 2014 Corporate Presentation WWW.ZARGON.CA

Zargon Oil & Gas Ltd. March 2014 Corporate Presentation WWW.ZARGON.CA

Advisory Forward-Looking Information Forward Looking Statements This presentation offers our assessment of Zargon's future plans and operations as at March 11, 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, 2014 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 unstrategic 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. Forwardlooking 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. 2

Zargon: Long life oil exploitation projects fund dividends and then deliver growth commencing in 2015 3 Conventional Waterflood Projects: Provide very low oil production declines, Provide substantial inventory of low risk oil exploitation wells to offset low decline, Support dividend through the rest of the decade. Little Bow ASP Enhanced Recovery Project: Provides oil production growth, then stabilized oil production well into the next decade, Scalable technology that can be used for subsequent Little Bow phases and ultimately other fields. Oil Exploitation Long lived Assets Dividend Paying 6,630 boe/d (Q1 2014 guidance) 4,300 bbl/d stable oil exploitation base 75+ prospective oil exploitation locations 21.0 Mmbbl of 2P oil reserves (12.4 yr. rli) 68% of 2P oil reserves are developed producing reserves Low oil decline rates Payout ratio of 35% (2013 w/o DRIP) Yield of 9.1% (based on share price of $7.94) $343 million in dividends/distributions paid over history

Zargon Overview (As at March 7, 2014 unless otherwise stated) Capitalization Toronto Stock Exchange: Symbols: ZAR; ZAR.DB Common Shares Outstanding: 30.10 million (basic) Market Capitalization: $239 million ($7.94 per share) (1) Net Debt at Dec. 31, 2013: $116 million Historical Returns Returns in dividends and distributions: $343 million ($17.30 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: 9.1% (1) 2013 Production Equivalent: 7,468 boe/d Oil: 4,870 bbl/d (65% of production) Gas: 15.59 mmcf/d (1) Based on a monthly dividend rate of $0.06/share and using the March 7, 2014 closing share price of $7.94. 4

Financial Highlights Financially Strong $165.0 million bank line with approximately $40 million drawn at December 31, 2013. $57.5 million Convertible Debenture maturing in 2017, yielding 6% annually. Net debt at December 31, 2013 (including bank debt, debentures and working capital deficiency) is $116 million; leaving over $100 million of available credit. 2013 Results Funds Flow from Operations, $1.95 per basic share. $58.48 million Dividends Paid, $0.72 per basic share ($0.06 per month). $20.35 million (after DRIP) Payout ratio of 35% based on 2013 funds flow; (37% before DRIP). Commencing September 2013, DRIP program was suspended. 2013 Capital Program Conventional Spending, $41 million. Little Bow ASP Spending, $35 million (long term facility construction). Net Property Dispositions, $34 million. Net Capital Program, $42 million 5

Forecast Oil Production Trends 7,000 6,000 Oil Production (bbl/day) 5,000 4,000 3,000 2,000 1,000 0 Q1 2013 History Q2 Q3 Q4 Q1 2014 Base Prod. @ 14% decline Estimate Q2 Q3 Q4 Q1 2015 ASP Phase 1 &2 increment Drilling Increment Base production and drilling increment are funded by annual $35 million conventional (non ASP) capital budget. Q2 Q3 Q4 Q1 2016 Q2 Q3 Q4 Zargon estimates base oil production is declining at 14% per year. McDaniel proved and probable developed producing case estimates a 15% decline (2015 versus 2014). Drilling increment assumes an annual $35 million conventional budget (18 net oil wells in 2014). Historical data identifies the property sales that were used to fund the ASP project. 6

2014 Objectives Zargon s 2014 objectives are: Finish the commissioning of the Little Bow ASP project on budget, with first chemical injections occurring by the end of the 2014 first quarter. Deliver Little Bow Phase 1 ASP operational and production targets of an incremental 350 barrels of oil per day by year end (increasing to a 2015 average rate of 900 barrels of oil per day). Finalize the design of the Little Bow Phase 2 ASP project and advance the Little Bow Phase 3 and 4 ASP engineering studies. Deliver a consistent dividend of $0.06 per common share per month. Execute a continuing property divestiture program designed to high grade and concentrate the Company s asset portfolio on our core oil exploitation projects. Direct a high graded oil exploitation program focused on our five long life low decline oil exploitation properties (Williston Basin, Taber, Bellshill Lake, Little Bow non ASP and Hamilton Lake). Maintain a strong balance sheet. 7

8 Oil Exploitation Properties (Conventional Oil Exploitation Projects)

Conventional Oil Exploitation Projects Current Drilling Inventory Property Project Net Locations Comments Hamilton Lake Multi frac horizontals 25+ Will require waterflood re implementation, large upside Bellshill Lake Increase fluid withdrawal 10 Facility optimization; infills and step outs Bellshill Lake Killam Develop Glauconite pool 10 Implement waterflood concurrently with development Taber Expand & enhance waterflood 5 Expand waterflood Williston Basin Elswick, Midale, Weyburn, Ralph, Steelman, Mackobee 25+ Horizontal drainage wells in relatively tight reservoirs; pressure support required in some cases Total Available 75+ Large inventory of oil exploitation opportunities The 18 well 2014 conventional oil exploitation drilling budget includes 9 Williston Basin, 4 Taber and 5 Bellshill Lake oil wells. The existing oil exploitation well inventory will support stable oil production volumes for many years. 9

Long-Life, Low-Decline Oil Production Base 7,000 Zargon Corporate Decline Analysis Total Oil Production Rate Gross W.I. Oil Production Rate ( bbl/day ) 6,000 5,000 4,000 3,000 2,000 1,000 0 2012 Additions 2011 Additions 2010 Additions 2009 Additions 2008 Additions Base Production Severe Breakup Spring 2011 2005 2006 2007 2008 2009 2010 2011 2012 Data to Dec 31, 2012 Production Wedge Base 2008 2009 2010 2011 2012 Dec 2012 Contribution 58% 4% 5% 9% 14% 11% Average 2013 Decline Rate 5.4% 20.7% 21.8% 14.4% 28.0% 37.5% 14.3% Vintage Zargon operated production plot highlights Zargon s low decline oil production decline of 14%. 10

Conventional Assets: Low Corporate Decline and High PDP Reserves Average Annual Decline Rate (%) 0 10 20 30 40 50 Proved Producing Reserves (% of P+P) 0 20 40 60 80 100 Zargon 11 Average 31% Source: Peters & Co. Limited, Intermediate & Junior Universe (February 10, 2014) Generally, reflects 2012 year end reserve data Average 36%

Existing Canadian Alkaline Surfactant Polymer 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 Grande Prairie Mooney (Black Pearl) 2011 In Progress Scheme Approved Edmonton Strathmore Suffield (Terrex) (Cenovus) 2007 Calgary Little Bow (Zargon) Taber (Husky) 2008 Lethbridge Taber South (Husky) 2006 Alberta Sask. Coleville (Penn West) 2011 Battrum (Hyak Energy) Fosterton 2013 (Husky) 2012 Gull Lake (Husky) Bone Creek 2009 (Husky) Medicine Hat Instow Grand Forks (Talisman) (CNRL) 2007/11 12

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. Objective Wash out more oil from an existing reservoir. a) Water Injection: More than half of oil is trapped Rock b) Alkali / Surfactant Mobilizes trapped oil Rock Surfactants (Detergent): Mobilizes trapped oil Water Injection Trapped Oil Droplet Water Alkali & Surfactant Solution Mobilized Oil Droplet Alkali: Increases effectiveness of the surfactant Polymer (Thickener): Thickened water helps sweep oil from the reservoir Water Injector a) Water Injection b) Polymer Injection Producer Polymer Solution Injector Increased Contact Volume Producer 13

ASP Chemical Flooding Injection Sequence 1 ASP Injection A Blend of Alkali, Surfactant & Polymer mobilizes trapped oil 2 Polymer Push Polymer displaces mobilized oil to producing wells 3 Terminal Waterflood Completes the Displacement OIL BANK ASP POLYMER WATER Little Bow Phase 1 & 2 Injection Schedule 2013 2014 2015 2016 2017 2018 2019 2020 2021 Phase 1 ASP Polymer Waterflood Phase 2 ASP Polymer 14

Little Bow ASP Project Enhanced Oil Recovery EOR With Proven Technology EOR in a mature, southern Alberta Waterflood Little Bow ASP: Phase 1&2 Development Alberta 15-18W4 Project Capital: $61 Million (excludes chemical) $42 million incurred through Q4 2013 (from 2012/01) Little Bow Little Bow Mannville P Pool $7 million remaining in 2014 to Phase 1 Startup $12 million in 2015 (Phase 2) Little Bow Mannville I Pool Zargon Land Zargon Wells Phase 1 Area Phase 2 Area Current Little Bow Oil: 400 bbl/d First ASP Injection: March 2014 Zargon Forecast Incremental Oil Rate: 2014 Exit: 350 bbl/d 2015 Avg: 900 bbl/d 2016 Avg: 1,550 bbl/d Zargon Forecast Incremental Oil Recovery: 5.2 Million Barrels (12% DOIIP) McDaniel Proved and Probable Incremental Oil Recovery: 4.5 Million Barrels (1.5 Million Barrels Proved) 15

Little Bow ASP Project Milestones ACCOMPLISHMENTS Essentially, have completed ASP project, meeting November 2012 cost estimates On track for March 2014 first injections (August 2013 updated schedule) 2014 Q1 ASP facility construction & battery upgrades complete Commissioning and Startup First ASP injections in March 2014 November 12, 2013 Photo Courtesy STRIKE Energy Services 16

Little Bow ASP Analog ASP Project: Husky Taber Mannville B 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% Oil Production (bbl/d) 10,000 1,000 100 First ASP Injection May, 2006 Oil Rate, bbl/d Sep-05 Oil Cut (%) Sep-07 Taber Production History Sep-08 Sep-10 Sep-12 Sep-11 Sep-09 Sep-06 8 % R.F.?? 10 % R.F. ERCB DPIIP = 43.1 mmbbl ASP Recovery Ult. Recovery * % mmbbl mmbbl 8 3.4 20.5 10 4.3 21.3 12 5.2 22.2 14 6.0 23.0 16 6.9 23.9 * Ultimate Recovery where ASP flood returns to pre ASP levels 12 % R.F. 14 % R.F. 16 % R.F. 1000% 100% 10% Oil Cut (%) Little Bow Mannville I and P Pools (Zargon) Taber Mannville B Pool (Husky) 14.5 % R.F. (Husky Application) 8 % R.F. (Zargon PV10 Breakeven) 10 % R.F. 12 % R.F. (Zargon Base Case) 14 % R.F. 16 % R.F. 10 1% 15,000 16,000 17,000 18,000 19,000 20,000 21,000 22,000 23,000 24,000 25,000 Data to July-2013 Cumulative Oil Production (mbbl) 17

Little Bow ASP Development Optimization Study (Phases 1 & 2) Oil Recovery 1,276 cases run ASP Oil Recovery (mbbl) Zargon 2013 Optimized: 6,500 Zargon 2013 Economics: 5,200 McDaniel 2013 Year End: 4,500 ASP Oil Recovery Base Waterflood Recovery 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 18

Little Bow ASP Full Cycle Before Tax Economics Phases 1 & 2 (Discounted back to Jan. 2013) Phases 1&2 IRR (%) 19.4 PV 10 ($ millions) 38.1 F&D ($/bbl)* 26.2 Netback ($/bbl)* 52.4 Recycle Ratio* 2.0 Reserves (mbbl) 5,237 Capital ($ millions)** 61.0 Chemical ($ millions) 77.8 BOPD 2500 2000 1500 1000 500 Base Waterflood Little Bow ASP: Phases 1&2 Production Base W.F. Phase 2 Phase 1 Phase 2 12.1% Recovery 5.2 mmbbl Phase 1 0 2012 2014 2016 2018 2020 2022 2024 2026 2028 2030 $ 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 December 31, 2013: $42 Million 19

Little Bow ASP Upside Potential Millions of Dollars 700 600 500 400 300 200 100 0-100 Little Bow ASP Undiscounted Cash Flow (Net Zargon WI - Before Tax) Little Bow ASP Upside Phases 3&4 Development +2% DOIIP Recovery +10$/bbl Edmonton Price Sask EOR Royalty Little Bow ASP Phases 1&2 2012 2014 2016 2018 2020 2022 2024 2026 2028 2030 20

2014 Capital Programs, Dividends and Cash Flows Program Funding Considerations 2014 Capital Budget (February 2014 Press Release) Conventional Capital Program ASP Phase 1 Capital to Complete ASP Phase 1 Chemical Costs Total Capital $35 million $ 7 million $ 9 million $51 million 2014 Funds Flow after Dividends (Two Examples for Illustration Purposes) Funds Flow Examples $50 million $65 million Cash Dividends (DRIP is suspended) ($22 million) ($22 million) Available from Funds Flow $28 million $43 million Capital Requirements exceeding Funds Flow $23 million $8 million 2014 Funding Shortfall provided by Property Sales and Additional Debt 2013 Year End Debt $116 million $116 million Property Sales (Proposed) $5 million $5 million Additional Debt $18 million $3 million Total Sales and Debt $23 million $8 million Calculated 2014 Year End Debt $134 million $119 million Calculated 2014 year end debt levels represent 60% or less of the available debenture and bank lines of $222.5 million. In 2015 17, significant increases in Little Bow ASP cash flow will permit debt retirement. 21

Production Guidance (March 2014 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 (4,625 bbl/d reported) H1 2014 4,300 barrels per day (incorporates Q4 2013 property sales) 2014 Exit 4,650 barrels per day (incorporates 350 bbls/d of ASP production) 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 (15.9 mmcf/d reported) Q1 2014 14.0 million cubic feet per day (incorporates Q4 2013 property sales) 2014 Avg. 13.5 million cubic feet per day (dependant on magnitude and timing of property sales) 2014 Cost Assumptions: Operating average approximately $18.00 per boe (includes transportation and ASP costs) G&A average approximately $4.50 per boe 22

Net Asset Value Calculations at 2013 Year End NAV Calculation (Dec 31, 2013) Proved + Prob. McDaniel Est. (PVBT 10%) Undeveloped Land Deduct Est. Net Working Capital & Bank/Debenture Debt Net Asset Value Zargon Proved + Prob. Net Asset Value $ 469 million $ 17 million $ 116 million $ 370 million $12.29 per basic share Reserve Category PDP Total Proved P+PDP Proved & Prob. McDaniel PVBT 10% ($ million) 280 322 351 469 Net Asset Value ($ million) 181 223 251 370 Net Asset Value ($/basic share) 6.03 7.40 8.36 12.29 (McDaniel January 1, 2014 price forecast and 30.09 million basic Zargon shares as of December 31, 2013) 2013 Year End Reserves (Long life, low decline producing oil) 2P Equivalent Reserves: 27.7 million boe (RLI: 10.4 years) Oil Reserves: P+P 21.0 million bbl (RLI: 12.4 years) P+P Developed Producing 14.2 million bbl (RLI: 8.4 years) Proved Developed Producing 10.6 million bbl (RLI: 6.2 years) 23

Net Asset Value Breakdown: McDaniel Proved and Probable Reserves (2013 Yr. End) Core Conventional Properties Williston Basin Taber South Bellshill (incl. Killam) Little Bow Conventional Hamilton Lake Q4/13 Oil Prod. (bbl/d) 1,807 812 754 580 182 Q4/13 Gas Prod. (mmcf/d) 0.35 0.10 0.60 0.99 1.28 McD. Oil Res. (mmbbl) FDC Capital ($million) Subtotal Core 4,135 3.32 15.46 8.68 $ 30 $ 362 Core conventional property value of $362 million less December 31/13 net debt of $116 million leaves $246 million or $8.17 per Zargon share. 7.65 2.35 2.36 2.40 0.70 McD. Gas Res. (bcf) 0.95 0.20 2.26 2.25 3.02 $ 8 $ 3 $ 10 $ 1 $ 8 PV10 Asset Value ($million) $ 171 $ 66 $ 62 $ 48 $ 15 Other Assets Q4/13 Oil Prod. (bbl/d) Q4/13 Gas Prod. (mmcf/d) McD. Oil Res. (mmbbl) McD. Gas Res.(bcf) FDC Capital ($million) PV10 Asset Value ($million) Other Oil & Gas 330 11.02 1.03 29.86 $ 8 $ 41 Undeveloped Land From Seaton Jordan Report (230 thousand net acres) $ 17 Impact of Sales & Prior Period Adj s. in Q4 160 1.56 n/a n/a n/a n/a Subtotal Other 490 12.58 1.03 29.86 $ 8 $ 58 Incremental ASP Assets Q4/13 Oil Prod. (bbl/d) Q4/13 Gas Prod. (mmcf/d) McD. Oil Res. (mmbbl) McD. Gas Res.(bcf) FDC Capital ($million) PV 10 Asset Value ($million) Subtotal ASP nil nil 4.48 1.72 $ 83 $ 66 Grand Total 4,625 15.90 20.97 40.26 $ 121 $ 486 24 Little Bow ASP and other assets add $124 million of value, or $4.12/share; resulting in a total net asset value of $12.29 per share (30.09 million shares).

Key Takeaways at Current Share Price (March 7, 2014) Zargon is committed to the current $0.06 per share monthly dividend. Current 9.1% 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; for 2014 the ASP construction capital is mostly completed and in 2015 the Little Bow ASP project provides significant free cash flow. 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 $7.94 per share. Investors buy Zargon at a discount to the proved and probable net asset value for Zargon s core conventional assets that require only minimal future development costs to realize cash flows. The Little Bow ASP project value and all other non core assets come for free. 25

WWW.ZARGON.CA Appendices

Little Bow ASP Full Cycle Economics Phases 1 & 2 Price Sensitivity: Before Tax IRR 30 25 Little Bow ASP Phases I & 2 Sask. Type EOR Royalty IRR vs. Price (Before Tax) IRR (%) 20 15 10 Base Price 5 0 $65.00 $75.00 $85.00 $95.00 $105.00 $115.00 Edmonton Light ($/bbl) Little Bow Field Realization = Edmonton Light less $18/bbl 27

Little Bow ASP Development Expansion: Phases 1-4 ZAR W.I. (%) W.I. DOIIP * (mmbbl) Phases 1 & 2 LB I Pool 100 31 LB P Pool 100 8 Followup U&W Unit 75 21 MM Unit 100 5 C8C / X8X 81 7 Total 72 * ERCB DOIIP Data Little Bow Phase 1-4 Injection Schedule 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 Phase 1 ASP Polymer Waterflood Phase 2 ASP Polymer Waterflood Phase 3 ASP Polymer Waterflood Phase 4 ASP Polymer 28

Little Bow ASP Full Cycle Before Tax Economics Phases 1-4 (Discounted back to Jan. 2013) Little Bow ASP: Project Economics Phases 1&2 Phases 1 4 IRR (%) 19.4 21.8 PV 10 ($ millions) 38.1 67.8 F&D ($/bbl)* 26.2 24.3 Netback ($/bbl)* 52.4 53.7 Recycle Ratio* 2.0 2.2 BOPD 3000 2500 2000 1500 1000 ASP Development Forecast - Phases 1-4 Base W.F. Phase 1 Phase 2 Phase 3 Phase 4 Zargon W.I. Production Phases 1&2 12% Recovery Phases 3&4 11% Recovery Reserves (mbbl) 5,237 8,825 500 * Injectant booked as Capital EDM Flat 85 Pricing Zargon Net W.I. 0 2012 2014 2016 2018 2020 2022 2024 2026 2028 2030 Working Interest Capital and Chemical Costs ($ Millions) Phases 1&2 Phases 3&4 Capital ** 61.0 15.9 Chemical 77.8 61.5 ** Capital Incurred to December 31, 2013: $42 Million 29

Williston Basin Production Trends & Orientation Map Ongoing Activities Exploit long life low decline pools with horizontal wells and waterflood enhancements. Saskatchewan Manitoba 2014 Activities Drill 9 additional horizontal wells. Upgrade 2 central batteries (Weyburn and Mackobee Coulee). Modify and enhance exisiting waterflood projects (Steelman and Ralph). Ralph Weyburn Frys Steelman Producing Oil Rate (bbl/day) 3,500 3,000 2,500 2,000 1,500 1,000 500 0 2013 Additions 2012 Additions 2011 Additions 2010 Additions 2009 Additions 2008 Additions Base Wells Core Property Group Williston Basin Gross W.I. Basis Elswick 2007 2008 2009 2010 2011 2012 2013 Estevan Workman North Dakota Mackobee Coulee Truro Haas 30

Taber South Sunburst Hz Oil Development & Waterflood Producing Oil Rate (bbl/day) 1,200 1,000 800 600 400 200 2012 Additions 2011 Additions 2010 Additions 2009 Additions 2008 Additions Base Wells Core Property Group Taber Area Gross W.I. Basis 0 2007 2008 2009 2010 2011 2012 2013 Ongoing Activities Exploit long life pool with horizontal wells and waterflood. 2014 Activities Drill 3 additional horizontal wells. Convert 2 additional wells to water injection. Increase water handling capacity at 14 11 battery. 31

Greater Bellshill Lake Area Production Trends & Orientation Map Bellshill Lake 1,000 Core Property Group Bellshill Lake Group 2013 Q4 Drilling Program Producing Oil Rate (bbl/day) 800 600 400 200 2012 Additions 2011 Additions 2010 Additions 2009 Additions 2008 Additions Base Wells Pilot Waterflood Commenced 2013 Q4 0 2007 2008 2009 2010 2011 2012 2013 Bellshill Killam 32 Ongoing Activities Expanded Bellshill Lake fluid handling capacity has providing 2013 and 2014 pumping upgrade opportunities. Bellshill Killam pilot waterflood commenced operations in Q4 2013. 2014 Activities 4 vertical and 1 horizontal wells budgeted at Bellshill Lake.

Hamilton Lake Viking Oil Unit Horizontal Drilling Large oil resource opportunity Ongoing Activities 3 Wells drilled in Q4/2012 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; will return to the project in 2015. Producing Oil Rate (bbl/day) 500 400 300 200 100 2013 Additions 2012 Additions 2011 Additions 2010 Additions 2009 Additions 2008 Additions Base Wells Core Property Group Hamilton Lake Gross W.I. Basis Zargon HZ Wells Q4/2012 Horizontal MultiFrac Test Wells 0 2007 2008 2009 2010 2011 2012 2013 33

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. 34

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: 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 400 bbl/d at $99.60 Cdn/bbl (WTI) Q4 2014: 2,200 bbl/d at $90.51 US/bbl (WTI) and 400 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 $3.33/gj (AECO) Q2 2014: 9,000 gj/d at $3.69/gj (AECO) Q3 2014: 9,000 gj/d at $3.69/gj (AECO) Q4 2014: 7,000 gj/d at $4.01/gj (AECO) Q1 2015: 6,000 gj/d at $4.25/gj (AECO) 35

Zargon Oil & Gas Ltd. March 2014 Corporate Presentation WWW.ZARGON.CA