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WWW.ZARGON.CA

ASP Project Update

April 18, 2013

Advisory – Forward-Looking Information

Forward-Looking Statements - This presentation offers our assessment of Zargon's future plans and operations as at April 18, 2013, and contains forward-looking statements. Such statements are generally identified by the use of words such as "anticipate", "continue", "estimate", "expect", "forecast", "may", "will", "project", "should", "plan", "intend", "believe" and similar expressions (including the negatives thereof). In particular, this presentation contains forward-looking information as to Zargon’s corporate strategy and business plans, Zargon’s oil exploration project inventory and development plans, Zargon’s dividend policy and the amount of future dividends, future commodity prices, Zargon’s expectation for uses of funds from financing, Zargon’s capital expenditure program and the allocation and the sources of funding thereof, Zargon’s cash flow and dividend model and the assumptions contained therein and the results there from, anticipated payout rates, 2012 production and other guidance and the assumptions contained therein, estimated tax pools, Zargon’s reserve estimates, Zargon’s hedging policies, Zargon’s drilling, development and exploitation plans and projects and the results there from and Zargon’s ASP project plans, capital expenditures, costs and the results therefrom. By their nature, forward-looking statements are subject to numerous risks and uncertainties, some of which are beyond our control, including such as those relating to results of operations and financial condition, general economic conditions, industry conditions, changes in regulatory and taxation regimes, volatility of commodity prices, escalation of operating and capital costs, currency fluctuations, the availability of services, imprecision of reserve estimates, geological, technical, drilling and processing problems, environmental risks, weather, the lack of availability of qualified personnel or management, stock market volatility, the ability to access sufficient capital from internal and external sources and competition from other industry participants for, among other things, capital, services, acquisitions of reserves, undeveloped lands and skilled personnel. Risks are described in more detail in our Annual Information Form, which is available on our website. Forward-looking statements are provided to allow investors to have a greater understanding of our business.

You are cautioned that the assumptions, including, among other things, future oil and natural gas prices; future capital expenditure levels; future production levels; future exchange rates; the cost of developing and expanding our assets; our ability to obtain equipment in a timely manner to carry out development activities; our ability to market our oil and natural gas successfully to current and new customers; the impact of increasing competition; our ability to obtain financing on acceptable terms; and our ability to add production and reserves through our development and acquisition activities used in the preparation of such information, although considered reasonable at the time of preparation, may prove to be imprecise and, as such, undue reliance should not be placed on forward-looking statements. Our actual results, performance, or achievement could differ materially from those expressed in, or implied by, these forward-looking statements. We can give no assurance that any of the events anticipated will transpire or occur, or if any of them do, what benefits we will derive from them. The forward-looking information contained in this presentation is expressly qualified by this cautionary statement. Our policy for updating forward-looking statements is that Zargon disclaims, except as required by law, any intention or obligation to update or revise any forward-looking statements, whether as a result of new information, future events or otherwise.

Barrels of Oil Equivalent - Natural gas is converted to a barrel of oil equivalent (“Boe”) using six thousand cubic feet of gas to one barrel of oil. In certain circumstances, natural gas liquid volumes have been converted to a thousand cubic feet equivalent (“Mcfe”) on the basis of one barrel of natural gas liquids to six thousand cubic feet of gas. Boes and Mcfes may be misleading, particularly if used in isolation. A conversion ratio of one barrel to six thousand cubic feet of natural gas is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead. Given that the value ratio based on the current price of crude oil as compared to natural gas is significantly different from the energy equivalency of 6:1, utilizing a conversion ratio on a 6:1 basis may be misleading as an indication of value.

The estimates of reserves and future net revenue for individual properties may not reflect the same confidence level as estimates of reserves and future net revenue for all properties, due to the effects of aggregation. Estimated reserve values disclosed in this presentation do not represent fair market value. 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.

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Little Bow ASP

Enhanced Oil Recovery Project

Oil rate today: 400 bpd

ASP Capital (Non Chemical): $ 60 Million

Forecast Oil Rate in 2016: 1,500 bopd

Forecast Oil Rate in 2018: 1,800 bopd

Forecast Oil Recovery: 4.9 Million Barrels

2009 Little Bow assets acquired from Masters Energy Inc.

2010 Reservoir Studies

2011 Lab Work, Facilities Scoping Studies

2012 Well workovers, Detailed Engineering,Key Equipment Orders; Reservoir Study Update

2013 Construction: Facilities and Pipelines, Chemical Supply

2014 Startup

Project Evolution

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Little Bow Mannville “I” and “P” Pools

Little Bow ASP: Phase 1&2 Development

Little Bow

Alberta 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

• High Quality Upper Mannville Reservoir

• Zargon WI: 100 %

• First Production: 1974

• Mature Waterflood (initiated 1983)

• Permeability (Avg): 1,500 mD

• Depth: 3,600 ft

• Porosity (Avg.): 23%

• Phased ASP Development

What is ASP?

Contact more reservoir, and get more oil from reservoir that is contacted.

• Surfactants (Detergent): mobilizes trapped oil

• Alkali: Increases effectiveness of the surfactant

• Polymer: Thickener. Thickened water is able to contact more reservoir

Polymer “thickens” the injected fluid to increase the volume of reservoir contacted.

Injector Producer

WaterWater

Injector Producer

Polymer

Solution

IncreasedContactVolume

Polymer

Solution

IncreasedContactVolume

a) Water Injection b) Polymer Injection

RockRock

a) Water Injection:More than half of oil is “trapped”

b) Alkali / SurfactantMobilizes trapped oil

Alkali and Surfactant act together to mobilize oil trapped in the reservoir. The injected fluids must contact the trapped oil to be effective.

Water Injection

TrappedOil

Water

RockRock

Mobilized Oil

Alkali & SurfactantSolution

A dilute chemical blend (Alkali, Surfactant and Polymer) added to an existing waterflood to “scrub” out oil that waterflooding alone cannot recover

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ASP Chemical Flooding – Injection Sequence

Injection Sequence

1) ASP: A blend of Alkali, Surfactant and Polymer mobilizes trapped oil

2) Polymer “Push”: Polymer solution displaces mobilized oil to producing wells

3) Terminal Waterflood: Completes the displacement

Phase 1 ASP Polymer Waterflood

Phase 2 ASP Polymer Waterflood

20212017 2018 2019 20202013 2014 2015 2016

Canadian ASP Projects

In Progress

Scheme Approved

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)

5

100

1,000

10,000

100,000

1964 1968 1972 1976 1980 1984 1988 1992 1996 2000 2004 2008 2012

Oil

Pro

du

ctio

n &

Wa

ter

Inje

ctio

n (b

pd

)

0%

1%

10%

100%

Oil C

ut (%

)

Data to Jan - 2013

Injection

Oil Cut

Oil Rate

Husky Taber and Zargon Little Bow Mannville PoolsAnalogous Production History

Lethbridge

Taber Mannville ‘B’

Pool (Husky)

Little Bow Upper Mannville

‘I’ and “P” Pool (Zargon)

6 miles

Taber

Lethbridge

Taber Mannville ‘B’

Pool (Husky)

Little Bow Upper Mannville

‘I’ and “P” Pool (Zargon)

6 miles

Taber

Zargon Little Bow Production History

Husky ASP Flood

Initiated

Husky Taber Production History

100

1,000

10,000

100,000

1974 1978 1982 1986 1990 1994 1998 2002 2006 2010 2014

Oil

Pro

du

cti

on

& W

ate

r In

jec

tio

n (

bp

d)

0%

1%

10%

100%

Oil C

ut (%

)

Data to Jan-2013

Injection

Oil Cut

Oil Rate

100

1,000

10,000

100,000

2000 2002 2004 2006 2008 2010 2012 2014

Oil

Pro

du

cti

on

(b

pd

)

0.1%

1.0%

10.0%

100.0%

Oil C

ut (%

)

Data to Jan-2013

Oil Cut

Oil Rate

Initial Oil: 300 bpd

Peak Oil: 1814 bpd

Peak Oil Cut: 13%

Initial Oil Cut: 2%

ASP Injection Polymer Injection

Husky Taber Mannville “B” ASP Flood

Maintaining Strong Performance

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1%

10%

100%

20% 25% 30% 35% 40% 45% 50% 55%

Cumulative Oil Produced ( % DPIIP )

Oil

Cu

t (%

)

Data to Jan-2013

Oil Cut

ERCB Assigned DPIIP: 43.1 MMbbl

Terminal

WaterfloodASP Polymer

12% DPIIPBase Waterflood

Decline

ASP Flood

Decline

Husky Taber Mannville “B” ASP Flood

ASP Flood Reserves

• Multiple development scenarios

modeled based on:

- ASP chemical concentration

and injection volume

- Drilling & workover locations

- Pattern design

• Study nearing completion

• Runs predict up to 7 million

barrels of incremental ASP

recovery

Little Bow ASP Development Optimization Study

Oil

Re

cove

ry (

%)

Waterflood Simulation Recovery: 36 %

1,276 cases run

ASP Recovery Factor

10% McDaniel Recognized12% Zargon Evaluation

0

4

8

12

16

ASP Incremental Oil Recovery

(% DPIIP)

• Updated reservoir

simulation model used

to optimize Little Bow

ASP Flood design

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Little Bow ASP Project Description

ASP Facility Site

Travers Gas Plant16-31 Battery

Zargon Land

Zargon Wells

Zargon Land

Zargon Wells

Zargon Land

Zargon Wells

Phase 1 Area

Phase 2 Area

Phase 1 Area

Phase 2 Area

Little Bow ASP: Phase 1&2 Development Areas

Little Bow ASP Facility

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Phases 1&2 Capital and Chemical

• Phase 1 costs include: $ 6.5 million from 2012

• Phase 2 costs occur in 2014 and 2015.

• Capital reported in “as spent” dollars.

• On a PV10 basis: Capital = $ 58.0 MM, Chemical = $ 49.5 MM.

Phase 1 Phase 2 Total($MM) ($MM) ($MM)

ASP Facility 30.0 1.7 31.7

Battery 9.5 3.2 12.7

Pipelines 2.2 3.2 5.4Water Disposal/Source 1.5 0.0 1.5

Subsurface/Surface/other 4.3 4.2 8.5

47.5 12.3 59.7

ASP Chemical 32.6 34.0 66.6

Total 80.1 46.3 126.3

Key Project Suppliers

Polymer Injection and Water

Treatment Equipment

VariousSNF, Ecodyne,

Anderson Water

Systems

Engineering, Procurement &

Construction Management

Calgary, CanadaWood Group PSN

Reservoir SimulationCalgary, CanadaCMG

ASP FormulationCalgary, CanadaWeatherford Labs

ASP FormulationGolden, ColoradoSURTEK

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Project Execution

January 2013

• ASP Development Optimization Study preliminary results

• ASP Facility 3D model Operability and Safety review

February 2013

• Class III cost estimate completed

• Civil Earthworks engineering package at “Issued For Bid” status

• Design frozen

March 2013

• ASP Chemical Supply proposals received and reviewed

• Utility Electrical: Fortis proposal accepted by Zargon

• Groupline Project Underway

• Civil Construction Packages prepared (Earthworks and Piling)

Q1 2013 Project Highlights

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Zargon Little Bow ASP Facility16-31-014-18W4April 2013

• ERCB regulatory approval

for construction

• Award Civil earthworks and

piling contracts

• Civil earthworks commences

• Groupline project completed

• Positioned to award ASP chemical contracts

May 2013

• Award Mechanical/Electrical contact

• Piling commences

Upcoming Milestones

Project Economics

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Little Bow ASP: Phases 1&2 Production

0

200

400

600

800

1000

1200

1400

1600

1800

2000

2012 2014 2016 2018 2020 2022 2024 2026 2028 2030

BO

PD

Base W.F. Phase 1 Phase 2

Phases 1&2 Economics Production and Metrics (Before Tax)

* Chemical booked as Capital

$85 Flat Edmonton Pricing

Chemical as Opex: PI10 = 0.62 and Recycle Ratio = 3.2

12% Recovery

4.9 mmbbl

Phase 1

Phase 2

Base Waterflood

Phases 1&2

ROR (%) 18.5

PV10 ($MM) 36.1

PI10* 0.34

F&D ($/bbl)* 25.9

Netback ($/bbl)* 52.2

Recycle Ratio 2.0

Payout (yr) 7.2

Reserves (mbbl) 4,874

BTax IRR vs. Price

0

5

10

15

20

25

30

$65.00 $75.00 $85.00 $95.00 $105.00 $115.00

Edmonton Light ($/bbl)

IRR

(%

)

Little Bow ASP Phases 1&2

EOR Royalty

Reform

Phases 1&2 EconomicsPrice Sensitivity

Ba

se P

rice

Little Bow Field Realization = Edmonton Light Less 17 $/bbl

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Followup Development: Phases 3&4

Phases 1 & 2

8100LB “P” Pool

Followup

781C8C / X8X

1968U&W Unit

70Total

5100 MM Unit

31100LB “I” Pool

W.I. DPIIP*

(mmbbl)ZAR

W.I. (%)

* ERCB DPIIP Data

Little Bow Phases 1 - 4 Injection Schedule

Phase 1 ASP Polymer Waterflood

Phase 2 ASP Polymer Waterflood

Phase 3 ASP Polymer Waterflood

Phase 4 ASP Polymer

2021 2022 20232017 2018 2019 20202013 2014 2015 2016

ASP Development Forecast - Phases 1- 4

0

500

1000

1500

2000

2500

3000

2012 2014 2016 2018 2020 2022 2024 2026 2028 2030

BO

PD

Base W.F. Phase 1 Phase 2 Phase 3 Phase 4

Zargon W.I. Production

Phases 3&4 Benefit From Existing Facility

Phases 1&2

12% Recovery

Phases 3&4

11% Recovery

Working Interest Capital and Chemical Costs ($ Millions)

Phases 1&2 Phases 3&4

Capital 59.8 15.6

Chemical 66.6 53.4

Little Bow ASP: Phases 1&2 and 1-4

Phases 1&2 Phases 1-4

IRR (%) 18.5 21.1

PV10 ($MM) 36.1 67.0

PI10* 0.34 0.46

F&D ($/bbl)* 25.9 23.8

Netback ($/bbl)* 52.2 53.0

Recycle Ratio* 2.0 2.2

Payout (yr) 7.2 7.9

Reserves (mbbl) 4,874 8,189

* Injectant booked as Capital

EDM Flat 85 Pricing

Zargon Net W.I.

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Upside Potential

Little Bow ASP

Undiscounted Cash Flow (Net Zargon WI - Before Tax)

-100

-50

0

50

100

150

200

250

300

350

400

450

500

550

600

2012 2014 2016 2018 2020 2022 2024 2026 2028 2030

Mil

lio

ns

of

Do

lla

rs

Little Bow ASP Phases 1&2

Little Bow ASP Upside

Phases 3&4 Development

+2% DPIIP Recovery

+10$/bbl Edmonton Price

EOR Royalty Reform

Conclusions

• The number of commercial ASP projects, and industry’s experience with the technology is increasing

• Construction of Phase 1 of the Little Bow ASP Project is proceeding for 2014 startup

• Oil Recovery: 4.9 mmbbl (Phases 1&2)

• This will be the central facility in a development program encompassing multiple oil pools and providing a decade of development opportunity to Zargon

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WWW.ZARGON.CA

ASP Project Update

April 18, 2013