Corporate Presentation January 21, 2016 zargon.ca Forward - - PowerPoint PPT Presentation

zargon.ca

Corporate Presentation

January 21, 2016

Forward Looking-Advisory

Forward-Looking Statements - This presentation offers our assessment of Zargon's future plans and operations as at January 21, 2016, 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, 2016 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 2016 and beyond, strategic alternatives review process, the source of funding for our 2016 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

• n 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.

2

Investment Highlights

• The 2015 year end reserve report has 21 proved plus an additional 11

probable undeveloped locations.

• Very low-decline conventional waterflood properties augmented by more

than 43 prospective development locations not included in the reserve report.

• High operatorship (~89%) characteristics.
• High light/medium oil and liquids weighting (~84%).
• Low production decline (~13% for oil and liquids).
• Proved and Probable Oil Reserves 18.58 mmbbl (66 percent developed producing).

Zargon Assets ASP Assets (Little Bow) Conventional Light and Medium Oil

3

• Tertiary Alkaline Surfactant Polymer Flood (“ASP”): Little Bow ASP tertiary

recovery project provides years of oil production growth.

• Following the construction and initial AS chemical injection phases, these

assets will provide years of steady production and free cash flows with only minor capital investments.

Core Areas

Williston Basin Little Bow ASP Project (Phase 1 & 2) Alberta Plains

• Q4 2015 production of 1,679 bbl/d and 0.28 mmcf/d.
• Proved and probable reserves of 7,659 mbbl and 1.21 bcf at Dec 31, 2015.
• Proved and probable producing reserves of 6,431 mbbl and 1.16 bcf at Dec 31, 2015.
• Exploitation upside: 19 recognized and 35+ additional waterflood and water drive oil

exploitation wells.

• Q4 2015 production of 1,471 bbl/d and 3.39 mmcf/d.
• Proved and probable reserves of 5,215 mbbl and 9.95 bcf at Dec 31, 2015.
• Proved and probable producing reserves of 4,183 mbbl and 5.53 bcf at Dec 31, 2015.
• Exploitation upside: 13 recognized and 10+ additional waterflood and water drive oil

exploitation wells.

• Q4 2015 prod: 423 bbl/d and 0.36 mmcf/d (phase 1); 62 bbl/d and 0.20 mmcf/d (phase 2).
• Proved and prob. reserves of 5,710 mbbl and 2.74 bcf at Dec 31, 2015 (phases 1 & 2).
• Proved and prob. producing reserves of 1,602 mbbl and 1.63 bcf at Dec 31, 2015 (phases

1 & 2).

• The Little Bow ASP project brings very large long term oil upside.

4

Zargon Overview (January 21, 2016)

Capitalization – Toronto Stock Exchange: Symbols: ZAR; ZAR.DB – Common Shares Outstanding: 30.37 million (basic) – Market Capitalization: $14 million ($0.465 per share) (1) – Net Debt at December 31, 2015 (unaudited):

• approx. $121 million, comprised of
• Convertible Debentures (6%)

$58 million (face value – June 2017 maturity)

• Net Working Capital Deficit

$ 3 million

• Bank Debt

$60 million

• Authorized Bank Debt

$88 million

– Insider Ownership: 3.35 million shares (11 percent) Q4 2015 Production – Equivalent: 4,340 boe/d – Oil: 3,635 bbl/d (84% of production) – Gas: 4.23 mmcf/d Q3 2015 Financial Results – Q1-Q3 Funds Flow from Operations $0.68 per basic share ($20.5 million) – Q3 Funds Flow from Operations $0.11 per basic share ($3.3 million) Strategic Alternatives Process (Scotiabank) – Progress Report to Shareholders by end of March 2016

(1) Using the January 20, 2016 closing share price of $0.465.

5

Key Developments

• August 13, 2015 Q2 Release and Announcement of Strategic Alternatives Review:
• Board forms a Special Committee to identify and consider strategic and

financial alternatives available to the Company with the ultimate goal of maximizing shareholder value.

6

Strategic Alternatives Review Announced

• January 21, 2016 Annual Reserves Press Release:
• Proved and Probable Oil & Liquids – 18.6 million barrels (14.0 year RLI),
• Proved & Prob. Producing Oil & Liquids – 12.2 million barrels (9.2 year RLI),
• Proved and Probable NAV of $4.84 per share,
• Proved Developed Producing NAV of $1.15 per share, and
• 2016 capital budget reduced to $9 million.
• November 11, 2015 Q3 Release and Dividend Update:
• Monthly dividend of $0.01 per common share is suspended.
• $25 million 2015 capital budget is reaffirmed. Cost savings permit the addition
• f thee additional ASP infill wells without an increase in budget funds.

Dividend Update 2015 Year End Reserves

Zargon’s Response to Extended Low Oil Prices

Current Situation

• Zargon has low decline, long-life oil exploitation assets that are well suited for providing free cash flow

at higher oil prices.

• Although delayed, the Little Bow ASP project has recently improved significantly and provides

substantial upside.

• At higher prices, the Williston Basin conventional exploitation well inventory and the Little Bow ASP

project provide ready and defined investments with attractive go-forward half-cycle reinvestment

• returns. In particular, the Williston Basin battery facilities are in place for future infill wells and the ASP

central facilities and prior chemical costs are sunk, so future costs can provide attractive half cycle returns.

• In the current pricing environment, Zargon’s debt levels are high; a situation that needs to be

addressed by June 2017 when $57.5 million of 6% convertible debentures mature.

The Response

• Zargon has focused on cost containment and has made good progress with operating, g&a and capital

cost reductions.

• Technical problems with the Little Bow ASP project have been addressed.
• Despite restricted capital programs, corporate oil production volumes and debt levels can be stabilized

provided an approximate $40 US per bbl pricing is achieved in 2016.

Strategic Alternatives Process

• Zargon’s key objective is to maximize returns for shareholders.
• To this end, the Board has formed a “strategic alternatives” committee that will examine all strategic

and financial options, including property sales, and a corporate sale or merger. Scotia Waterous is advising the committee.

• Upon consideration of market trends and tone, Zargon will provide shareholders an update regarding

this process prior to the end of the 2016 first quarter. 7

Waterflood/drive Well Inventory

Property Project Net Hz Wells Comments Bellshill Lake Increase fluid withdrawal 6+ Facility optimization; infills and step-outs Killam Glauconite Other Plains North Develop Glauconite pool Morinville, Carrot Creek 8+ 3+ Infill and step-out locations Infill and step-out locations Taber South and Taber SE Develop Sunburst pools 8+ Expand and enhance waterfloods Williston Basin Elswick, Huntoon, Weyburn, Frys, Ralph, Steelman, Carnduff, Truro, Haas, Mackobee 50+ Horizontal drainage wells in relatively tight reservoirs; additional pressure support required in some cases

Drilling Inventory of 75+ net horizontal wells. Over the last couple of years, conventional oil exploitation drilling activities have been curtailed as the Company has been allocating available capital to the Little Bow ASP project. As these wells are mostly additions to existing depletion schemes, the average targeted production is 25-40 bbl/d with average reserves of about 50-80 thousand barrels. In the current low-cost environment, all-in well costs generally vary from $0.8 to $1.2 million.

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Williston Basin Locations

Drilling Inventory

• Since summer 2014, Zargon has drilled only three (fall 2014) Williston Basin wells, as essentially all

discretionary capital has been redirected to the Little Bow ASP project. Zargon has more than 50 Mississippian locations available that are generally characterized as pressure supported (water drive or waterflood) long-life low-decline opportunities.

• All of these locations are associated with upgraded central battery and water disposal/injection facilities.

Since 2010, Zargon has invested approximately $13 million in facility upgrades and turnarounds to meet updated and more stringent regulatory compliance initiatives.

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Horizontal Drilling Locations Steelman 2 Midale/Frobisher Weyburn 6 Midale/Frobisher Elswick 5+ Midale Ralph 5+ Midale Carnduff 3 Midale Huntoon 6+ Midale multifrac Frys 5+ Tilston Haas 6+ Glenburn (Alida) Truro 2 Bluell (Frobisher) Mackobee 10 Bluell (Frobisher) Total 50+ Locations

North Dakota Saskatchewan Manitoba

Long-Life, Low-Decline Oil Production

Using Zargon operated historical production plots, we calculate base annual oil production declines of 13%. Independent research by Peters calculates a 14% base corporate annual decline. The McDaniel proved and probable developed case predicts a 11% average corporate annual oil decline. Three different sources confirm industry low corporate declines that help support Zargon through this low price period.

Comparative Declines Source: Peters & Co. Limited, Intermediates & Juniors (Jan. 18, 2016) Oil sands and SAGD producers are not included.

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Zargon Corporate Decline Analysis - Total Oil Production Rate

1,000 2,000 3,000 4,000 5,000 6,000 Jan-05 Jan-06 Jan-07 Jan-08 Jan-09 Jan-10 Jan-11 Jan-12 Jan-13 Jan-14

Gross W.I. Oil Production Rate ( bbl/day )

2014 Additions 2013 Additions 2012 Additions 2011 Additions 2010 Additions 2009 Additions Base Production

Data to Dec 31, 2014 Dec 2014 Contribution Decline Rate Base 64% 7.6% 2011 11% 8.7% 2012 7% 17.0% 2013 5% 21.4% 2014 12% 35.0%

Weighted average oil decline rate of 13%

10 20 30 40 50

Average Annual Decline Rate (%) Average 28%

Zargon

Little Bow ASP

EOR in a mature Southern Alberta Waterflood

Recent Developments

• Jan. 2016: ASP Cumulative injection: 6.6 million barrels
• 29% of Phase 1 injection (ASP and polymer only).
• Q3 2015: Successful exploitation program enables a

return to full and balanced injection. Three new producers drilled and on production. Early production results are encouraging.

• December 2015: Three additional producers drilled. Two
• n production by year end.
• January 2016: Commencing mid-February, Zargon will

defer AS injections until oil prices improve ($45 US/bbl WTI).

Little Bow ASP: Phase 1&2 Development

15-18W4

Zargon Land Zargon Wells Zargon Land Zargon Wells Phase 1 Area Phase 2 Area Phase 1 Area Phase 2 Area Little Bow Mannville “P” Pool Little Bow Mannville “I” Pool

Historical Capital

• Total facility cost to YE 2014: $50 million.
• Ultimate target oil (10+% recovery of 80+ mmbbl ooip)
• 2014 ASP Chemical: $12 million.
• 2015 Optimization: $7 million.
• 2015 ASP Chemical: $12 million.

2016 Capital (Phase 1)

• Exploitation Costs: $1 million.
• Chemical Costs: $5 million (if AS suspended until year

end).

• Chemical Costs: $8 million (assumes AS injections

resumed in Sept. 2016). 2016 Production (Phase 1)

• 600 bbl/d (400 bbl/d incremental to waterflood).

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2015 Summer/Fall Optimization

• Successful optimization program to improve reservoir areal

conformance and reserves capture.

• Included the drilling of three producers, producer workovers,

injector stimulations and two injector conversions.

• The cause of the injection pipeline failures was determined and

remedied.

• Reliable operations since late September have resulted in a 30

percent increase in ASP injection rate over summer levels, which will drive both improved oil cuts and total fluid production.

2015 Fall Optimization & Winter Drilling

2015 Winter 2015 Drilling Program

• Three well December 2015 program targeting structural highs

in high oil cut areas of the reservoir. (Drilling from existing surface leases: minimal pipeline costs.)

• Significant cost savings have been delivered for the 2015
• ptimization and drilling programs.
• Total 2015 ASP exploitation capital was approximately $7

million.

• Recent oil production rates and oil cut trends have been

encouraging.

Oil Producer Waterflood Injector ASP Injector Summer Drilling Location Winter Drilling Location Conversion to ASP Injector

Phase 1 Scheme Boundary

Little Bow ASP Phase 1 – Winter Drilling

2015 Program

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Phase 1 Response and Updated Forecast

13

Zargon’s updated production forecast allows for AS suspension in February 2016. Production to resume upward trend, six months after resumption of AS injections.

Capital Expenditure Forecast Comparison

(all $ in millions)

Despite recent encouraging ASP technical trends, field oil prices have continued to deteriorate and Zargon will not be able to maintain stable 2016 corporate debt levels, without further capital reductions. Fortunately, the Little Bow ASP project has advanced far enough that Alkaline and Surfactant (“AS”) injections can be suspended for a few months without significantly effecting future tertiary oil

• recoveries. Consequently, “AS” injection will be suspended until oil prices improve materially ($45 US

per barrel WTI target). In the short term, due to reservoir transit time, the suspension of “AS” injections will not have an impact

• n ASP production trends, but after six months we anticipate ASP production growth will subside and

production volumes will stabilize until “AS” injections are recommenced.

14 Capital Program 2015 (Unaudited) 2016 (Nov. 15 forecast) 2016 (Jan. 16 forecast) ASP Phase 1 Exploitation $ 7.0 $ - $ 1.0 ASP Phase 1 Chemical Costs $12.0 $ 12.0 $ 5.0 Total ASP Capital $ 19.0 $ 12.0 $ 6.0 Conventional (non-ASP) Capital $ 6.0 $ 4.0 $ 3.0 Total Capital Program $ 25.0 $ 16.0 $ 9.0 Prior period Adjustments (from 2014 Dispositions) $ 0.6

Cost Reductions - Progress Made

Capital Costs G&A Costs

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Operating Costs

• Conventional Oil Exploitation Capital (defer all non-discretionary costs):

$38.1 million (2014), $6 million (2015 unaudited), $3 million (2016 budget).

• ASP Capital (defer Little Bow Phase 2; conclude 2015 optimization costs):

$10.2 million (2014), $7 million (2015 unaudited), $1 million (2016 budget).

• ASP Chemical Costs: $11.6 million (2014), $12 million (2015 unaudited), $5 or $8 million

(2016 budget), depending on if AS injections are resumed in September.

• Reduce operating costs through lower margin property sales (now completed),

comprehensive cost reviews, closed Stettler field office, lower Alberta electricity costs, lower contract operator fees, reduced Williston Basin turnaround and facility upgrade costs, reduced ASP facility and workover costs and lower pipeline spill and repair costs.

• Resulting cost performance:

$42.9 million (2014), $36.0 million (2015 unaudited), $31.4 million (2016 forecast).

• Reduce G&A costs through office staff reductions (38 percent), comprehensive cost

reviews, salary and consultant rate reductions and office space adjustments.

• Resulting cost performance (including one-time costs):

$13.4 million (2014), $8.4 million (2015 unaudited), $6.5 million (2016 forecast).

Williston Basin – 2016 Cash Flow Parameters

(No Drilling Case)

• Conv. Oil

1,530 bbl/d in 2016. compares to Q4 2015 rate of 1,679 bbl/d.

• Gas

0.40 mmcf/d; compares to Q4 2015 rate of 0.28 mmcf/d.

• Equiv.

1,600 boe/d in 2016; compares to Q4 2015 rate of 1,726 boe/d.

• Oil Prices

WTI to Zargon average Williston Basin field differential; $12.00 Cdn./bbl.

• Gas Prices

$2.0/mcf field price (Williston Basin price before processing).

• Royalties

Averaging 18 percent.

Production Costs Pricing Parameters

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• Operating

$11.5 million – down from $12.7 million est. in 2015 Improvements due to completed facility upgrades and lower contractor costs.

• US Taxes

Varies with oil price up to $0.2 million.

• Abd. & Reclam.

$0.6 million.

• Capital

$1.5 million maintenance capital (minor exploitation and facility costs).

Williston Basin – 2016 Cash Flow Estimates

(No Drilling Case – 1,600 boe/d)

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WTI Pricing FX (US/Cdn.) Field Pricing Field Cash Flow Free Cash Flow After All Capital, US Tax, Abandonments and Reclamations $35 US/bbl $0.69 $38.70 Cdn./bbl $ 6.5 million $ 4.4 million $45 US/bbl $0.72 $50.50 Cdn./bbl $11.9 million $ 9.8 million $55 US/bbl $0.75 $61.30 Cdn./bbl $16.9 million $14.7 million $65 US/bbl $0.78 $71.30 Cdn./bbl $21.5 million $19.3 million

• The existing Williston Basin properties

provide free cash flow at levels down to less than $35 US/bbl (WTI).

• For Zargon, these strong cash flows can

be used to retire debt.

• Alternatively, the cash flows can be used

to grow production by drilling high- graded locations, selected from a 50+ Williston Basin well inventory.

5 10 15 20 25 30 40 50 60 70 Cash Flow ($million) WTI Oil Price ($US/bbl)

2016 Williston Basin Cash Flow

Field Cash Flow Free Cash Flow

Alberta Plains – 2016 Cash Flow Parameters

Includes ASP, Alberta Plains North & South (No Drilling Case)

• Conv. Oil

1,420 bbl/d in 2016.

• ASP Oil (Phase 1) 600 bbl/d; 400 bbl/d incremental to waterflood.
• Total Oil

2,020 bbl/d compares to Q4 2015 rate of 1,956 bbl/d.

• Gas

3.50 mmcf/d; compares to Q4 2015 rate of 3.95 mmcf/d.

• Equiv.

2,600 boe/d in 2016; compares to Q4 2015 rate of 2,614 boe/d.

• Oil Prices

WTI to Zargon average Alberta Plains field differential; $17.20 Cdn./bbl.

• Gas Prices

$2.45/mcf field price.

• Royalties

Varies from 6 to 12 percent (for $35, $45, $55, $65 US/bbl cases).

Production Costs Pricing Parameters

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• Operating

$19.9 million – down from $23.3 million est. in 2015; due to lower electricity costs, lower contractor costs, improved base ASP operations, shut-in field

• ffice.
• Abd. & Reclam.

$0.9 million.

• ASP Capital

$1.0 million minor exploitation; $5.0 million chemical costs without AS ($35 and $45 US WTI); $8.0 million chemical costs if AS injections recommence in September 2016.

• Conv. Capital

$1.5 million maintenance capital (minor exploitation and facility costs).

Alberta Plains – 2016 Cash Flow Estimates

Includes ASP (No Drilling Case – 2,820 boe/d) No Drilling Case)

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WTI Pricing FX (US/Cdn.) Field Pricing Field Cash Flow Free Cash Flow After All Capital, Abandonments and Reclamations $35 US/bbl $0.69 $33.50 Cdn./bbl $ 6.3 million ($ 2.1 million) $45 US/bbl $0.72 $45.30 Cdn./bbl $13.7 million $ 5.3 million $55 US/bbl $0.75 $56.10 Cdn./bbl $20.2 million $ 8.8 million (AS resumed in Sept.) $65 US/bbl $0.78 $66.10 Cdn./bbl $26.0 million $14.6 million (AS resumed in Sept.)

• 5

5 10 15 20 25 30 30 40 50 60 70 Cash Flow ($ millions) WTI Oil Price ($US/bbl)

2016 Alberta Plains Cash Flow

Field Cash Flow Free Cash Flow

• Due to exceptionally low oil prices, Alkaline

and Surfactant (“AS”) injections have been deferred at the Little Bow ASP project.

• We plan on resuming the “AS” injections
• nce oil prices exceed $45 US/bbl (WTI).

The deferral of “AS” injections does not impact Little Bow 2016 ASP oil production, but will impact 2017 volumes.

• In the higher price scenarios, free cash flow

can be used either to pay down debt, drill Williston Basin / Alberta Plains oil exploitation wells or commence Little Bow phase 2 expenditures.

Corporate – 2016 Cash Flow Parameters

(No Drilling Case – 3,550 bbl/d and 3.9 mmcf/d)

• Conv. Oil

2,950 bbl/d in 2016.

• ASP Oil (Phase 1) 600 bbl/d; 400 bbl/d incremental to waterflood.
• Total Oil

3,550 bbl/d compares to 3,635 bbl/d in Q4 2015.

• Gas

3.90 mmcf/d; compares to Q4 2015 rate of 4.23 mmcf/d.

• Equiv.

4,200 boe/d in 2016; compares to Q4 2015 rate of 4,340 boe/d.

• Oil Prices

WTI to Zargon average field differential; $15.00 Cdn./bbl

• Gas Prices

$2.44/mcf average field price

• Avg. Royalties

Varies from 11.5 to 14.5 percent (for $35, $45, $55, $65 US/bbl cases).

Production Costs Pricing Parameters

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• Operating

$31.4 million – $20.5/boe, (down from approx. $36.0 million in 2015)

• Abd. & Reclam.

$1.5 million.

• US Taxes

varies with oil price up to $0.2 million.

• ASP Capital

$1.0 million minor exploitation; $5.0 million chemical costs without AS and $8.0 million chemical costs if AS injections recommence in September 2016.

• Conv. Capital

$3.0 million maintenance capital (minor exploitation and facility costs).

Corporate – 2016 Cash Flow Estimates

(No Drilling Case – 3,550 bbl/d and 3.9 mmcf/d) No Drilling Case)

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WTI Pricing Average Oil Production Field Cash Flow (excl. hedges) G&A, US Taxes, Hedges & Interest Costs Corporate Cash Flow Corporate Cash Flow After All Capital, Abandonments and Reclamations $35 US/bbl 3,550 bbl/d $12.8 million ($10.8 million) $ 2.0 million ($ 8.5 million) $45 US/bbl 3,550 bbl/d $25.7 million ($11.6 million) $14.1 million $ 3.5 million $55 US/bbl 3,550 bbl/d $37.1 million ($12.3 million) $24.8 million $11.3 million $65 US/bbl 3,550 bbl/d $47.5 million ($12.8 million) $34.7 million $21.2 million

• 10

10 20 30 40 50 60 30 40 50 60 70 Cash Flow ($ millions) WTI Oil Price ($US/bbl)

2016 Corporate Cash Flow

Field Cash Flow

• Corp. Cash Flow

Free Cash Flow

• By suspending “AS” injections at Little Bow,

Zargon is able to maintain relatively stable production and debt levels in a $35- $45US/bbl WTI environment.

• Once prices return to $45+ US/bbl levels,

Zargon can resume “AS” injection without increasing debt.

• At higher prices, Zargon’s assets provide

free cash flow (after capital and corporate costs) that can be used to retire debt or drill high-graded horizontal oil exploitation wells from our 75 oil well inventory.

Valuation based on 2016 Cash Flow Estimates

(No Drilling Case – 3,550 bbl/d and 3.9 mmcf/d) No Drilling Case)

22

WTI Pricing Field Cash Flow (excl. hedges) Six Times Field Cash Flow Zargon YE 2015 Net Debt Attributed to Zargon Shares Calculated Zargon Share Value $35 US/bbl $12.8 million $77 million $121 million $ nil $ nil $45 US/bbl $25.7 million $154 million $121 million $33 million $1.09/share $55 US/bbl $37.1 million $223 million $121 million $102 million $3.36/share $65 US/bbl $47.5 million $285 million $121 million $164 million $5.40/share

• Zargon’s long-dated oil reserves provide

investor’s exceptional torque (both

• perational and financial leverage) to future

increases in oil prices.

• Assuming a corporate valuation based on a

six times property multiple suggests that significantly higher share prices may be realizable once WTI oil prices rebound to higher levels.

0.00 1.00 2.00 3.00 4.00 5.00 6.00 30 40 50 60 70 Share Price ($ per share) WTI Oil Price ($US/bbl)

Zargon Share Value - Six times Property Cash Flow

Estimated Tax Pools (Sept. 30, 2015)

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At September 30, 2015, Zargon has approximately $290 million of very high quality Canadian tax pools that will shield cash flows for many years. Category Amount Annual Deductibility Canadian Exploration Expense $ 59 million 100% Non Capital Losses $118 million 100% Canadian Development Expense $ 37 million 30%, declining balance Canadian Oil & Gas Property Expense $ nil 10%, declining balance Canadian Undepreciated Capital Cost $ 71 million Primarily 25%, declining balance Other $ 5 million Various Total Tax Pools $290 million

Net Asset Value Comparison

NAV Calculation (Dec 31, 2014)

Proved + Prob. McDaniel Est. (BT DCF 10%) $ 407 million

Undeveloped Land

$ 12 million

Deduct Net Working Capital & Bank Debt

• $ 114 million

Net Asset Value

$ 305 million Zargon Proved + Prob. Net Asset Value $10.11 per share

Reserve Category McDaniel PVBT 10% ($ million) Net Asset Value ($ million) Net Asset Value ($/share) PDP 217 116 3.84 Total Proved 268 167 5.52 P+PDP 275 173 5.74 Proved & Prob. 407 305 10.11 (30.18 million shares at Dec 31, 2014)

NAV Calculation (Dec 31, 2015)

Proved + Prob. McDaniel Est. (BT DCF 10%) $ 259 million

Undeveloped Land (Seaton Jordan evaluation)

$ 9 million

Deduct Net Working Capital & Bank Debt

• $ 121 million

Net Asset Value

$ 147 million Zargon Proved + Prob. Net Asset Value $4.84 per share

Reserve Category McDaniel PVBT 10% ($ million) Net Asset Value ($ million) Net Asset Value ($/share) PDP 147 35 1.15 Total Proved 168 56 1.84 P+PDP 186 74 2.44 Proved & Prob. 259 147 4.84 (30.37 million shares at Dec 31, 2015)

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McDaniel & Associates Consultants Ltd.

January 1, 2016 WTI Price Forecast

25

0.00 20.00 40.00 60.00 80.00 100.00 120.00 140.00 2008 2011 2014 2017 2020 2023 2026 2029

WTI Price ($US/bbl)

Forecast History

WTI Crude Oil ($US/bbl) 2008 99.60 2009 61.80 2010 79.50 2011 95.10 2012 94.20 2013 97.95 2014 93.00 2015 48.85 Forecast 2016 45.00 2017 53.60 2018 62.40 2019 69.00 2020 73.10 2021 77.30 2022 81.60 2023 86.20 2024 87.90 2025 89.60 2026 91.40 2027 93.30 2028 95.10 2029 97.00 2030 99.00

McDaniel 2015 Year End Net Asset Value

Proved & Probable Reserves Basis

Proved and probable conventional property value of $186 million, less estimated December 31/15 net debt of $121 million leaves $65 million or $2.14 per Zargon share (excluding value for undeveloped land or high quality tax pools.) Little Bow ASP adds an additional $73 million, or $2.40 per share of proved and probable reserve value.

Waterflood & Waterdrive Properties

2015/Q4 Production McDaniel Reserves

McDaniel McDaniel Oil & Liquids (bbl/d) Gas (mmcf/d) Oil & Liquids (mmbbl) Gas (bcf) PV10 Asset Value ($million) Future Capital ($million)

Williston Basin 1,679 0.28 7.66 1.20 $ 105 $ 19 Alberta Plains North 717 1.74 2.43 7.02 $ 35 $ 8 Alberta Plains South (excl. Little Bow ASP) 754 1.65 2.78 2.94 $46 $ 4 Subtotal 3,150 3.67 12.87 11.16 $ 186 $ 31

2015/Q4 Production McDaniel Reserves McDaniel McDaniel Little Bow ASP Oil & Liquids (bbl/d) Gas (mmcf/d) Oil & Liquids (mmbbl) Gas (bcf) PV 10 Asset Value ($million) Future Capital ($million)

ASP Phase 1 423 0.36 3.46 1.62 $ 73 $ 22 ASP Phase 2 62 0.20 2.25 1.12 $ - $ 59 Subtotal 485 0.56 5.71 2.74 $ 73 $ 81 Grand Total 3,635 4.23 18.58 13.90 $ 259 $ 112 26

Net Asset Value per Share (based on 30.37 million shares outstanding)

Commodity Hedges

• Zargon uses hedges to help fund dividends and capital programs during periods
• f lower commodity prices.

Hedging Strategy Forward Oil Sales

27

• Oct. – Dec 2015: 1,500 bbl/d at $79.78 Cdn./bbl (WTI)
• H1 2016:

500 bbl/d at $79.30 Cdn.bbl (WTI)

2016 Cash Flow Projections

• Reduce debt in preparation for June 2017 maturity of $57.5 million of convertible

debentures.

• Maintain oil production at stable levels.
• Seek and evaluate shareholder value creation opportunities, which capture the inherent

value of Zargon’s long-life oil reserves.

Objectives Results Action Plan

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• $35 and $45 US/bbl WTI Cases: Projected field cash flows of $13 and $26 million are

completely/mostly consumed by capital and corporate costs.

• $55 and $65 US/bbl WTI Cases: Projected field cash flows of $37 and $48 million, provide

for either debt reduction (Zargon’s current outlook) or for funding oil exploitation drilling programs high-graded from a 75 well inventory (prospective purchaser outlook).

• Aggressively reduce capital, operating and G&A costs.
• Defer non-discretionary conventional oil exploitation capital; temporarily defer Little Bow

alkaline and surfactant injections (AS) while maintaining polymer flood.

Key Takeaways

• Zargon’s unique low-decline asset provides stable volumes in this challenging low price
• period. Due to these asset attributes, Zargon can navigate 2016 with $40 US/bbl WTI oil

prices (or better) while delivering stable oil production volumes and steady debt levels.

• Bank debt (unaudited) of $60 million at December 31, 2015 represents about 68% of $88

million authorized bank line. The additional $57.5 million convertible debenture does not mature until June 2017.

• Zargon’s Board and management believe that Zargon’s share price has not been reflective
• f the fundamental value inherent in the Company.
• In an improved oil price environment, Zargon’s conventional oil Williston Basin locations

and follow-up Little Bow ASP phases hold significant potential that could be accelerated by a better capitalized entity.

Balance Sheet (OK through June 2017) Strategic Process Initiated Deep Discount to NAV

29

• Investors buy Zargon at a large discount to the proved and probable (or proved

developed producing) net asset value when evaluated at prices above current strip.

• Despite recent encouraging production and oil cut trends, little or no value is attributed to

the Little Bow ASP project.

• Zargon’s long-dated oil reserves provide investor’s exceptional torque (both operational

and financial leverage) to future increases in oil prices.

zargon.ca

Property Appendices

ASP Enhanced Oil Recovery 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 will not recover.

• Surfactants: Detergent; mobilizes trapped oil.
• Alkali: Increases surfactant effectiveness.
• Polymer (Thickener): Thickened water helps sweep
• il from the reservoir.

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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

Return to waterflood to complete oil displacement

OIL BANK ASP POLYMER WATER

Phase 1 Fall 2015 Infill Drilling Results

02/11-32-014-18W4 04/13-32-014-18W4 04/16-31-014-18W4

1160 1165 1170 1175 1180 1185 1190 1195 1200 1 10 100 1000

Resistivity

1160 1165 1170 1175 1180 1185 1190 1195 1200 50 100 150

Gamma

1090 1095 1100 1105 1110 1115 1120 1125 1130 1 10 100 1000

Resistivity

1090 1095 1100 1105 1110 1115 1120 1125 1130 50 100 150

Gamma

1145 1150 1155 1160 1165 1170 1175 1180 1185 1 10 100 1000

Resistivity

1145 1150 1155 1160 1165 1170 1175 1180 1185 50 100 150

Gamma

Oil Bank Oil Bank Forming

Oil Bank Oil Bank Forming Flushed Zones Flushed Zones Flushed Zones Oil Bank Forming

• Combined rate of 120 bbl/d, confirming that oil banks are being formed at the top of the reservoir.

Producing oil rates and oil cuts are expected to improve with time (target oil cut up to 30%) as oil banks continue to form and move through the reservoir.

Current Oil Rate 67 bbl/d Oil Cut: 6% Current Oil Rate 3 bbl/d Oil Cut: 1% Current Oil Rate 50 bbl/d (initially 35 bbl/d) Oil Cut: 3% 32

Phase 1 Winter 2015 Infill Drilling Results

06/04-05-015-18W4 05/04-05-015-18W4 02/15-31-014-18W4

Initial Oil Rate 65 bbl/d Oil Cut: 29 %

• Two wells completed and on production. The oil bank is just arriving at the third well and we elected

to defer completion pending improved commodity pricing and offset evidence of oil banking.

Completion Pending

1090 1095 1100 1105 1110 1115 1120 1125 1130 1 10 100 1000

Resistivity

1090 1095 1100 1105 1110 1115 1120 1125 1130 50 100 150

Gamma

1090 1095 1100 1105 1110 1115 1120 1125 1130 1 10 100 1000

Resistivity

1090 1095 1100 1105 1110 1115 1120 1125 1130 50 100 150

Gamma

1080 1085 1090 1095 1100 1105 1110 1115 1120 1 10 100 1000

Resistivity

1080 1085 1090 1095 1100 1105 1110 1115 1120 50 100 150

Gamma

Flushed Zones

Oil Bank Forming Oil Bank

Oil Bank Forming Oil Bank Flushed Zones Oil Bank Forming

Initial Oil Rate 12 bbl/d Oil Cut: 9 % 33

Husky Taber Mannville “B” ASP Husky Gull Lake ASP

Analog ASP Performance (The Prize)

• The Taber Mannville B and Gull Lake ASP projects are good analogs to our Little Bow ASP

project.

• Successful ASP projects provide stable production volumes for many years after the first three

years of cost intensive AS injections are completed.

• Although our Little Bow production response was slower than anticipated, we continue to

foresee many years of production growth followed by many years of free cash generating stable production for our Little Bow property.

34

Little Bow ASP Project Analog

Taber Mannville “B” ASP Analog

• Most mature Canadian ASP project; Husky Operated
• Same geological setting, oil quality, reservoir size and pre-

ASP depletion state as Zargon’s Little Bow pool; ASP injection since 2006

• Incremental recovery greater than 12% is projected

Little Bow Mannville “I” and “P” Pools (Zargon) Taber Mannville “B” Pool (Husky)

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Taber Production History

May-14 May-13 May-12 May-11 May-10 May-09 May-08 May-07 May-06

8% RF 10% RF 12% RF 14% RF 16% RF 8% RF 10% RF 12% RF 14% RF 16% RF

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 1,000

Oil Cut (%)

Data to December 2014

Oil Cut (%) First ASP Injection May, 2006

AER DPIIP = 43.1 mmbbl ASP Recovery Pool Rec* Percent 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 * Recovery where ASP flood returns to pre-ASP levels

Original (2014) Development Plan

Zargon W.I. (%) W.I. DOIIP* (mmbbl)

Phases 1 & 2 LB “I” Pool 100 31 LB “P” Pool 100 8 Phases 3 & 4 U&W Unit 97 26 G Unit 95 10 MM Unit 100 5 Other C8C / X8X 100 9 Total 89

* AER DOIIP Data (Jan. 2014)

36

15-19W4 15-18W4 14-19W4 14-18W4

Zargon Land Zargon Wells

Phases 1&2 Area

“C8C/X8X” Pool “MM” Unit “G”, “U&W” Units

Phases 3&4 Area

Little Bow Phase 1 - 4 Injection Schedule Phase 1

ASP Polymer Waterflood

Phase 2

ASP Polymer Waterflood

Phase 3

ASP Polymer Waterflood

Phase 4

ASP Polymer

2022 2023 2024 2025 2020 2021 2026 2027 2013 2014 2015 2016 2017 2018 2019

• Project timing has been delayed; oil prices are

sharply lower and “full cycle” economics are challenged.

• However, Zargon’s ASP plant facilities can

ultimately provide 10-12% incremental tertiary recoveries on approximately 90 mmbbl of working interest oil-in-place.

• The ASP project brings significant option value

in a higher price environment.

Steelman – Free Cash Flow Stable Production

Exploration, Optimization, Waterflood

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Steelman Operated Properties -Production

100% 640 acres undeveloped Midale potential Net Operated Frobisher & Midale Production ~450b/d Oil Net Non-Op Production ~140 b/d Oil

• Midale & Frobisher Production – Conventional
• Large OOIP & low recovery factors
• Frobisher – High Permeability, large oil compartments,

multi zone targets (Exploitation & Exploration)

• Midale – Long life, sustainable production/cash flow &

low declines

• Stratigraphic traps (Attic Oil) & strong structural traps

(Oil saturated, underlying natural water drive mechanism)

• 3D Seismic Coverage
• Strong Netbacks & solid free cash flow generation
• Infrastructure control & disposal capabilities
• Successful Waterflood in place - Steelman Voluntary Unit #8
• Section 4 Midale waterflood initiated in fall 2015
• Potential Waterflood Frobisher - State A producers
• Strong Non-Op Assets ~WI 45%
• Optimization opportunities - High Volume Lift
• Extension Midale trend - potential development opportunities
• Gross/Net Acreage - 9.83/7.25 Sections

Midale Huntoon - Twp 6, Rge 10 W2

Exploitation Project – OOIP Increase RF

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Phi*H (m)

• Waterflood potential
• Large OOIP > 15-20+ MMbbl
• Current RF 4-8%
• Gross/Net Acreage 2.63/2.56 Sections
• Bypass Pay opportunities
• Potentially horizontal drill locations
• Enhance recovery - Potential to multi-stage fracture

stimulate the Midale/Vuggy interval

• Significant cumulative oil produced from offset

secondary recovery analogues

• Offset established waterflood analogue

Frys Tilston - Twp 7, Rge 30-31 W1

Exploitation Project – OOIP Increase RF

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• Gross/Net Acreage 4.3/4.3 Sections
• API Gravity 36.6o
• Potentially 10+ horizontal drill locations
• Significant cumulative oil produced – Zargon Lands 1.6 MMbbls
• Attic Oil at Tilston Subcrop

Potential Locations

Ralph Midale - Twp 7, Rge 13 W2

Waterflood Optimization Opportunities

40 Ralph Waterflood Production Performance – Midale Beds

Primary Development Secondary Development

Water Injection Wells PUD Locations Infill Locations Future Winj Conv.

• Established waterflood
• Strong stratigraphic trap
• Attic Oil
• Mapped OIP ~15MMbbl
• Current RF ~12%
• Long life sustainable asset
• Waterflood optimization potential
• Gross/Net Acreage 6.54/5.65 Sections
• Conventional horizontal infill drilling opportunities
• 1-3-8-13 Clean Oil pipeline connected to sales
• Battery Consolidation 15-29-7-13 to 1-3-8-13 Potential

North Dakota - Overview

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• Large OOIP
• Upside, bypass pay potential
• Stable production; 15.1 MMbbls oil produced to date
• Undeveloped land, Exploration opportunities
• Infrastructure & disposal in place
• WI 97.6% to 100% ownership
• Gross/Net Acreage 18.78/18.43 Sections
• Exploration & Exploitation plays
• Production optimization opportunities
• Established Waterflood & Unitized production
• Extensive 3D Seismic Coverage
• Long life conventional oil properties
• Conventional & Unconventional drilling plays
• 4 PPUD + undrained seismically defined horizontal targets

Haas Truro Mackobee Coulee

North Dakota - Optimization

Exploration & Horizontal Drill Targets

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Exploration Potential Hz Infill Drilling Potential Hz Infill Drilling Potential

Bellshill Lake

43

100 200 300 400 500 600 700 800 900 2007 2008 2009 2010 2011 2012 2013 2014 2015

Oil Rate (bbl/day)

• Medium gravity oil in high permeability Dina sands
• Continued development has produced a platform
• f stable oil production
• Infill and pool extension opportunities remain
• Recent increases in fluid handling capability provide

a platform for continued growth

• More than 5 infill locations are defined by available

2D & 3D seismic coverage

Killam Glauconite Property

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10 100 1,000 2010 2011 2012 2013 2014 2015 Oil Rate (bbl/day)

Data to May 31, 2015

• Significant oil-in-place medium gravity Glauconite oil

property

• Extensive infill development potential of more than 8

wells defined by extensive 2D & 3D seismic coverage

• Solution gas conservation in place
• Water injectivity has been confirmed and developing a

full scale waterflood pressure support scheme is possible

Taber South – Sunburst Oil Horizontal Development

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31 Horizontal wells drilled since 2007 - current production 600 bbls/d Waterflood expanding to north - currently 5 horizontal injectors 5 additional locations identified - development supported by 3D seismic (depth converted Sunburst amplitude below) Glauconite oil - development potential north of Sunburst pools

Taber South – Sunburst Hz Oil Production Growth

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Data to April 2015

Taber South – Sunburst Hz Oil OOIP and Recoveries

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OOIP South Pool – 15.5 million bbls

Recovery to date – 9.7% Forecast ultimate recovery – PDP-15.8%, PDP+P-18.3%

OOIP North Pool – 6.7 million bbls

Recovery to date – 15.3% Forecast ultimate recovery – PDP-19.8%, PDP+P-21.6%

North pool recovery to date is higher due to lower density oil (and vertical well recoveries) South pool is seeing stabilizing rates due to waterflood (vertical well historical production was negligible due to higher density oil)

North Pool

API – 20 deg

South Pool

API – 16 deg

zargon.ca

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