WWW.ZARGON.CA

Corporate Presentation

March 20, 2013

Advisory – Forward-Looking Information

Forward-Looking Statements - This presentation offers our assessment of Zargon's future plans and operations as at March 19, 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, 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 2013 and beyond, plans to sell un-strategic assets, the source of funding for our 2013 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.

Zargon Overview(As at March 19, 2013 unless otherwise stated)

Capitalization & Returns

– Listed on Toronto Stock Exchange in 1993: Symbols: ZAR; ZAR.DB

– Common Shares Outstanding: 29.95 million (basic)

– Market Capitalization: $ 220 million ($7.34 per share)

– Returns in dividends and distributions: $ 322 million ($16.58 per share)

Dividend & Yield

– Annualized Current Dividend: $ 0.72/share

– Yield at current share price: 9.8% (1)

– Q4 2012 DRIP Participation Rate: 12%

Q4 2012 Production Highlights

– Equivalent: 7,720 boe/d

– Oil: 5,065 bbl/d (66% of production)

– Gas: 15.93 mmcf/d

– Oil per basic share 170 bbl/d per million shares

2012 Year End Reserves (December 31, 2012)

– 2P Reserves: 31.2 million boe (RLI: 11.0 years)

– 2P Oil Reserves: 23.1 million bbl (RLI: 12.4 years)

– 2PDP Oil Reserves: 17.3 million bbl (RLI: 9.3 years)

– PDP Oil Reserves: 12.7 million bbl (RLI: 6.9 years)

(1) Based on a monthly dividend rate of $0.06/share and using the March 19, 2013 closing share price of $7.34.

Financial Highlights

• Financially Strong

– $57.5 million Convertible Debenture matures in 2017, yielding 6% annually

– $165 million bank line confirmed in October 2012 with approximately $36

million drawn at the end of Q4/2012

– Including net working capital deficiencies of $20 million and $57.5 million of

convertible debentures, Zargon’s year end 2012 debt is $113 million.

• Q4/2012 Results

– Funds Flow from Operations, $0.55 per basic share

– Using the Q4/2012 dividend rate of $0.06 per share per month

• Calculated payout ratio of 29% based on Q4 funds flow after 12% DRIP

participation (33% before DRIP).

• 2012 Cost Structure Improvements

– Focus on cost controls, reduced 2012 operating and G&A costs by $8.4 and

$2.3 million, respectively, from 2011 levels

Business Plan

Oil Exploitation (increasing reservoir oil recovery factors)

• Increase oil production, reserves and ultimate recoveries from existing oil pools through waterfloods, development drilling and other production optimization methods that now include Alkaline Surfactant Polymer (“ASP”) tertiary recovery projects.

• The business plan’s feedstock are underdeveloped oil-in-place assets. We are working on six discrete conventional oil exploitation projects plus the Little Bow ASP tertiary recovery project.

Long-Life, Low-Decline Oil Assets

• Long-life, low-decline oil exploitation (pressure supported) assets provide free cash flow that underpins our long term dividend strategy.

Risk Management

• Protect investor’s underlying asset base with conservative hedging, debt and financing practices.

Dividend Policy

• Disciplined cash flow dividend model encourages efficiencies and returns.

• Zargon is committed to deliver steady, but supportable dividends. Dividend payout levels are ultimately targeted to be in the 35%-50% of cash flow range, a level that is enabled by our current and developing low decline oil assets.

Oil Exploitation Properties(6 Conventional and 1 Tertiary ASP Project at Little Bow)

Williston Basin – Two Project Types

Midale Drainage Frobisher Structure

Frys Weyburn

Ralph Steelman

Elswick Mackobee Coulee

Haas

Truro

Conventional Oil Exploitation Projects

Visible Multi-Year Drilling Inventory & Project Opportunities

Large inventory of oil exploitation opportunities115+Total Available

High-Graded Program

Weyburn, Steelman, Mackobee

Elswick, Midale, Weyburn, Ralph, Steelman, Mackobee, Truro, Haas,

Workman

Project

Expand & enhance waterflood

Develop new pool

Increase fluid withdrawal

Multi-frac horizontals

Project

2013-16 high-graded program will promote strong returns (20 wells in 2013, then 22 per year)

86+

Undrained seismically defined horizontal targets10+Frobisher Structure

Horizontal drainage wells in tight reservoirs; pressure support required in some cases

30+Midale Drainage

CommentsNet

LocationsWilliston Basin

Expand waterflood; includes Taber Southeast pool10Taber South

Implement waterflood concurrently with development10Killam Glauconite

Facility optimization; infills and step-outs5Bellshill Lake

Will require waterflood re-implementation, large upside50+Hamilton Lake

CommentsNet

LocationsAlberta Plains

Conventional Properties Underpin Dividend

Oil Production Sustainability (before ASP growth):

Oil production (per share) is expected to be maintained steady during the 2014 through 2016 period

by drilling our existing non-ASP project inventory (based on the following assumptions):

$45 million annual field capital program required; annually 22 wells high-graded from 130+ well inventory

(excluding ASP); however only $40 million will be spent in 2013.

21% corporate average oil production decline rate.

$40,000 per bbl/d capital efficiencies (first year average oil rate).

During the 2013 “ASP heavy spend period” modest oil production per share losses will be incurred due

to reduced conventional capital budgets and property sales.

Dividend Sustainability:

Based on the following assumptions, the $0.06 per share monthly dividend is supported through 2016

from conventional properties.

$85 Cdn. per barrel average FOB Edmonton oil price (2013-16).

$3.85 Cdn. per mmbtu average AECO natural gas price (2013-16).

$21.00 per barrel of oil equivalent average operating, transportation and G&A cost.

An effective royalty rate of 19%, effective interest rate 5.5%.

$3 million annual site reclamations, nominal US cash taxes.

Historical Production Addition Costs Review

Production addition calculations can be very erratic in the short term due to the timing of new wells and the capital costs related to

facilities, land, etc. The Q4 2012 efficiencies were challenged due to poorer than anticipated Hamilton Lake and Williston

Basin drilling results, plus heavy infrastructure spending at Bellshill Lake, Taber and Hamilton Lake. Significantly

improved results are expected in 2013.

Analysis Assumptions:

- 21% annual corporate oil decline rate, and all capital is invested in oil projects

- excludes ASP capital expenditures and production additions from acquisitions or dispositions

- excludes 2011 Williston Basin summer flood related shut-ins

$0.0

$10.0

$20.0

$30.0

$40.0

$50.0

$60.0

$70.0

$80.0

Production Efficiency ($M/bbl/d) $37.7 $39.6 $37.0 $36.6 $60.7 $49.0 $40.3 $36.3 $28.6 $36.3 $33.0 $53.6 $75.9

Field Capital Spending ($MM) $12.8 $8.6 $12.8 $12.4 $15.1 $16.4 $10.6 $18.4 $22.3 $7.7 $18.0 $23.7 $20.8 $9.2 $9.0 $25.8

Quarter Production ( bbl/d) 4,560 4,780 5,382 5,485 5,554 5,740 5,850 5,437 5,893 5,034 5,330 5,619 5,496 5,384 5,079 5,065

Quarterly Change (bbl/d) 126 220 602 103 69 186 110 (413) 456 (859) 296 289 (123) (112) (305) (14)

Production Decline (bbl/d) 233 239 251 283 288 292 301 307 285 309 264 280 295 289 283 267

Net Production Acquired (bbl/d) 630 195 350 (205) (260) (275)

Sask. Flooding Shutins (bbl/d) (760) (160)

Oil Production Added (bbl/d) 359 (171) 658 386 357 128 616 (106) 741 210 980 569 172 452 (22) 253

2009

Q1 Q2 Q3 Q4

2010

Q1 Q2 Q3 Q4

2011

Q1 Q2 Q3 Q4

2012

Q1 Q2 Q3 Q4

4 Q

ua

rte

r M

ov

ing

Ave

rag

e

Oil

Pro

du

ctio

n E

ffic

ien

cy C

ost

($M

/bb

l/d

ay

)

Zargon Conventional Oil Exploitation Projects

Evaluations Based on Actual Zargon Field Results

$ 16,000$ 8.002.82254551$ 1,105 $ 4005 / 0Bellshill Lake (HZ Re-Entry)

$ 21,000$ 11.002.245364110$ 2,450$ 1,10010 / 5Taber Sunburst

$ 44,000$ 20.500.16416261$ 286 $ 1,80050+ / 0Hamilton Lake Viking [4]

$ 34,000$ 15.900.49416261$ 684$ 1,400With improved capital costs .

$ 50,000$ 16.500.51274258$ 680 $ 1,35010 / 1Killam Glauconite - Primary

$ 42,000$ 15.900.87406075$ 1,450$ 1,680Target Waterflood Well [5]

30+ / 1

10+ /0

Pot’l/

Booked

Wells [1]

$ 52,800$ 17.601.14245275$ 1,493$ 1,320Williston Basin Midale

$ 21,500$ 15.002.025811384$ 2,495$ 1,240Williston Basin Frobisher

Production [3]

Addition

Efficiency

($/bbl/d)

F&D

($/BOE)

P.I.R.

@ 10%

6 Month

Oil Rate

(bbl/d)

30 Day

Oil Rate

(bbl/d)

Oil

Reserves

(Mbbl)

PV@10%

($M) [2]

CAPEX

($M)Project Name

Notes: [1] potential locations and undeveloped locations in 2012 year end reserves report

[2] using base oil price of $85.00 Cdn at Edmonton

[3] based on six month production

[4] prior to drilling cost improvements and using production from the initial 5 well drilling program

[5] waterflood costs allocated to wells

Hamilton Lake Viking Oil UnitHorizontal Drilling – 3 Well Program in Q4

Q4/2012 Horizontal MultiFrac Test WellsZargon HZ Wells

3 Wells drilled in Q4/2012

31 API gravity sweet crude

Developed in the 1960’s

Waterflood was prematurely suspended in the 1980’s

High reservoir pressure due to over injection

Drilled 8 multi-frac horizontal wells

Hamilton Lake Viking Oil UnitHistoric Well Performance & Type Curve

Well Production History Dataset Average Type Curve

Hamilton Lake - Horizontal MultiFrac Wells

1

10

100

1,000

00

-01

00

-02

00

-03

00

-04

00

-05

00

-06

00

-07

00

-08

00

-09

00

-10

00

-11

00

-12

01

-01

01

-02

01

-03

Year-Month on Production

Fie

ld E

stim

ate

d D

aily

Oil

Pro

du

ctio

n (

bb

l/d

ay

)

( Initial 5 well drilling program results )

-500

0

500

1,000

1,500

60 65 70 75 80 85 90 95 100 105 110

2013 Oil Price (FOB Edmonton) ( $Cdn/bbl )

Be

fore

Ta

x D

CF

@ 1

0%

( $

M )

Hamilton Lake Viking - Primary Depletion Type Curve Evaluation

Hamilton Lake Viking Oil Unit Type Curve Economic Parameters

6230 day rate (bbl/d)

61Reserves - Oil (Mbbl)

165- Gas (MMcf)

34,000Efficiency ($/bbl/d)

15.90F&D ($/BOE)

0.49P.I.R. @ 10%

2.5Payout (yrs)

32%IRR (%)

416 Month Rate (bbl/d)

88Total (Mboe)

$ 686PV10 ($M)

$ 1,400CAPEX ($M)

Analysis Using Base Pricing

(with fall 2012 capital costs)

2013 “Base Price”

Edm. Light $85.00/bbl

Field Price $79.00/bbl

• Production profile based on initial 5 well horizontal drilling program

• Hamilton Lake holds a large oil exploitation resource with significant potential.

Based on Fall

2012 Costs

Ba

se P

rice

Improved fall well costs of $1.4

million, down from previous

costs of $1.8 million

Historic Costs

Optimized. OPEX ($/bbl) $ 9.20

Taber South Sunburst Hz Oil Development & Waterflood

2012 Activities

• Expand Horizontal Waterflood

‒ Improve injectivity of existing wells

‒ Converted one additional injector

• In Q4 drilled 2 hz. oil wells

Forecast 2013 Activities

• Drill 5 additional horizontal wells

• Convert 2 additional wells to water injection

• Increase water handling capacity at 14-11 battery

Production Contribution by Drilling Program Date

0

100

200

300

400

500

600

700

800

900

1,000

2007 2008 2009 2010 2011 2012

Oil

Ra

te (

bb

l/d

ay

)

Base 2008 2009 2010 Q1 2011 Q3 2011

1 well converted to water injection

2 wells converted

Data to Jul 31, 2012

Hz Oil Well

Hz Water Injector

Q4/2012 Hz Well

Injector Conversion

Phase 2

Waterflood

Phase 1

Waterflood

Sunburst Pool

Outline

Taber South Sunburst Waterflood Project Historic Well Performance & Type Curve

Taber Sunburst - Horizontal Oil Exploitation Project

1

10

100

1000

00

-01

00

-03

00

-05

00

-07

00

-09

00

-11

01

-01

01

-03

01

-05

01

-07

01

-09

01

-11

02

-01

02

-03

02

-05

02

-07

02

-09

Year-Month on Production

Fie

ld E

stim

ate

d D

ail

y O

il R

ate

( b

bl/

day

)

Well Production History Dataset Average Type Curve

Taber South Sunburst Waterflood Project Type Curve Economic Parameters

6430 day rate ( bbl/d)

21,000Efficiency ($/bbl/d)

11.00F&D ($/BOE)

2.24P.I.R. @ 10%

0.9Payout (yrs)

153%IRR (%)

536 Month Rate (bbl/d)

100.0Reserves - Oil (Mbbl)

$ 2,450PV10 ($M)

$ 1,100CAPEX ($M)

Analysis Using Base Pricing

0

500

1,000

1,500

2,000

2,500

3,000

3,500

4,000

60 65 70 75 80 85 90 95 100 105 110

2013 Oil Price (FOB Edmonton) ( $Cdn/bbl )

Be

fore

Ta

x D

CF

@ 1

0%

( $

M )

Taber Sunburst Oil Project - Type Curve Evaluation

Ba

se P

rice

OPEX ($/bbl) $ 8.00

2013 “Base Price”

Edm. Light $85.00/bbl

Field Price $70.50/bbl

• Waterflood operations provide low-declines, long-life production.

• Further drilling and expansion of the waterflood will continue in 2013.

Williston Basin Orientation Map

Estevan

North Dakota

Saskatchewan Manitoba

Haas

Truro

Mackobee Coulee

Frys

Steelman

Ralph

Elswick

Weyburn

Workman

Williston Basin Midale Drainage WellsHistoric Well Performance & Type Curve

Well Production History Dataset Average Type Curve

Williston Basin - 2010 & 2011 Midale Drilling Program

1

10

100

1,000

00

-01

00

-01

00

-03

00

-04

00

-05

00

-06

00

-07

00

-08

00

-09

00

-10

00

-11

00

-12

01

-01

01

-02

01

-03

01

-04

01

-05

01

-06

01

-07

01

-08

01

-09

01

-10

01

-11

01

-12

Year-Month on Production

Fie

ld E

stim

ate

d D

ail

y O

il P

rod

uct

ion

( b

b/d

l )

Williston Basin Midale Drainage Wells Type Curve Economic Parameters

5230 day rate ( bbl/d)

53,000Efficiency ($/bbl/d)

17.60F&D ($/BOE)

1.14P.I.R. @ 10%

2.4Payout (yrs)

45%IRR (%)

246 Month Rate (bbl/d)

75.0Reserves – Oil (Mbbl)

$ 1,493PV10 ($M)

$ 1,320CAPEX ($M)

Analysis Using Base Pricing

0

500

1,000

1,500

2,000

2,500

3,000

3,500

60 65 70 75 80 85 90 95 100 105 110

2013 Oil Price (FOB Edmonton) ( $Cdn/bbl )

Be

fore

Ta

x D

CF

@ 1

0%

( $

M )

Williston Basin Drainage Project (Midale) Type Curve

Ba

se P

rice OPEX ($/bbl) $ 7.00

2013 “Base Price”

Edm. Light $85.00/bbl

Field Price $74.70/bbl

• Midale wells have moderate initial productivity but also low initial decline rates.

• Strong economic returns with long-life production.

Little Bow ASP Project

• Zargon has sanctioned the construction of

an ASP Project in the Little Bow area of

Southern Alberta.

• Expect to increase oil recovery from this

mature waterflood by 12% of DPIIP

(4.9 million barrels).

• Regulatory scheme approval received.

• Detailed engineering design nearing

completion. Class 3 estimates are

prepared. Design packages for

construction bids in Q1 2013.

• Long lead time and major equipment

orders have been placed.

• First ASP Injection: January 2014

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

ASP Chemical Flooding Recovers Bypassed Oil

ASP floods utilize:• Surfactants (detergent) to mobilize

oil that waterflooding alone leaves trapped in the reservoir

• Alkali added to increase the efficiency of the injected surfactants

“Recovers more oil from reservoir rock contacted by chemical”

• Polymer thickens the injected water and improves reservoir sweep

“Contact more reservoir rock”

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

Injector Producer

WaterWater

Injector Producer

PolymerSolution

IncreasedContactVolume

PolymerSolution

IncreasedContactVolume

a) Water Injection b) Polymer Injection

RockRock

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

b) Alkali / SurfactantMobilizes trapped oil

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

Water Injection

TrappedOil

Water

RockRock

Mobilized Oil

Alkali & SurfactantSolution

ASP Chemical Flooding – Injection Schedule

Injection Sequence

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

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

3) Terminal Waterflood: Completes the displacement

Canadian ASP Projects

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)

Little Bow ASPRecent Project Milestones

December 2012

• ASP Facility and Battery HAZOP

• ASP and Battery Capital Cost reduction program

January 2013

• ASP Development Optimization Update 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

• P&IDs matured. Design frozen

• ASP pipeline project underway

• Well workovers proceeding

Zargon Little Bow ASP Facility16-31-014-18W4

• 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 ASPDevelopment Optimization Study

Oil

Re

cove

ry (

%)

Waterflood Simulation Recovery: 36 %

1276 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

100

1,000

10,000

100,000

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

Oil P

rod

uc

tio

n &

Wa

ter

Inje

cti

on

(b

pd

)

0%

1%

10%

100%

Oil C

ut (%

)

Data to July 2012

Injection

Oil Cut

Oil Rate

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

1972 1976 1980 1984 1988 1992 1996 2000 2004 2008 2012

Oil P

rod

ucti

on

& W

ate

r In

jec

tio

n (b

pd

)

0%

1%

10%

100%

Oil C

ut (%

)

Data to July 2012

Injection

Oil Cut

Oil Rate

100

1,000

10,000

100,000

2000 2002 2004 2006 2008 2010 2012

Oil

Pro

du

cti

on

(b

pd

)

0.1%

1.0%

10.0%

100.0%

Oil C

ut (%

)

Data to July 2012

Oil Cut

Oil Rate

Initial Oil: 300 bpd

Peak Oil: 1814 bpd

Peak Oil Cut: 13%

Initial Oil Cut: 2%

ASP Injection Polymer Injection

Husky Taber Mannville “B” ASP FloodContinued Strong Performance

Husky Taber Mannville “B” ASP FloodASP Flood Reserves

1%

10%

100%

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

Cumulative Oil Produced ( % DPIIP )

Oil

Cu

t (%

)

Data to July 2012

Oil Cut

ERCB Assigned DPIIP: 43.1 MMbbl

Terminal

WaterfloodASP Polymer

12% DPIIPBase Waterflood

Decline

ASP Flood

Decline

Little Bow ASPPhase 1&2 Capital Costs

• Phase 1 costs: $6.5 million in 2012 and $38.0 million in 2013, $3 million in 2014.

• 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.

• F&D costs (including undiscounted chemical costs through 2019) is $25.90/bbl.

• Predicted field net backs of $50+/bbl using $68/bbl field price (Bow River stream pricing).

• Estimated field recycle ratio: 2.0.

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 5.4

Water Disposal/Source 1.5 0.0 1.5

Subsurface/Surface/other 4.3 4.2 8.6

47.5 12.3 59.8

ASP Chemical 32.6 34.0 66.6

Total 80.1 46.3 126.4

Little Bow ASP - Phase 1&2

Capital & Chemical Costs and BTax NCF(As Spent $ - Annual)

-50

-40

-30

-20

-10

0

10

20

30

40

50

2012 2014 2016 2018 2020 2022 2024 2026 2028 2030$ M

illio

ns

-150

-120

-90

-60

-30

0

30

60

90

120

150

Cu

mu

lativ

e ($

Millio

ns

)

Capital+Chem NCF Cumulative NCF

Little Bow ASPPhase 1&2 Capital & Net Cash Flow (Btax)

Field pricing based on Edmonton $85/bbl Flat Pricing

Little Bow ASPPhase 1&2: Internal Project Economics (BTax)

* Chemical booked as Capital

$85 Flat Edmonton Pricing

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

Little Bow ASP: Phase 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

12% Recovery

4.9 mmbbl

Phase 1

Phase 2

Base Waterflood

Phase 1&2

IRR (%) 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 Phase I & 2

EOR Royalty

Reform

Little Bow ASPPhase 1&2 Price Sensitivity: BTax IRR

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

Ba

se P

rice

BTax IRR vs. Oil Recovery

0

5

10

15

20

25

30

8 9 10 11 12 13 14 15 16

Recovery (% DPIIP)

IRR

( %

)Little Bow ASP Phase I & 2

EOR Royalty

Reform

Little Bow ASPPhase 1&2 Recovery Sensitivity: BTax IRR

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

Ba

se P

rice

Little Bow ASP 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 - Phase 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

Little Bow ASPPhase 1-4 Internal Project Economics (BTax)

Phase 1&2

12% Recovery

Phase 3&4

11% Recovery

Phase 3&4 Capital Costs (Zargon Net W.I.)

Phase 3 Phase 4 Total($MM) ($MM) ($MM)

Battery 4.9 0.0 4.9Pipelines 2.4 1.7 4.1

Subsurface 3.2 3.4 6.610.5 5.1 15.6

ASP Chemical 26.1 27.2 53.4

Total 36.6 32.4 69.0

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

Phase 1&2 Phase 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.

Little Bow ASP Upside Potential

Little Bow ASP

Undiscounted Cash Flow (Net Zargon WI - Before Tax)

-100

-50

0

50

100

150

200

250

300

350

400

450

500

550

600

2012 2014 2016 2018 2020 2022 2024 2026 2028 2030

Mil

lio

ns

of

Do

lla

rs

Little Bow ASP Phase 1&2

Little Bow ASP Upside

Phases 3&4 Development

+2% DPIIP Recovery

+10$/bbl Edmonton Price

EOR Royalty Reform

Current ASP Project Funding Status

• Bank Lines

– Bank lines set at $165 million in October 2012 review.

– Zargon has approximately $109 million of unused borrowing capacity as at December 31, 2012.

• Little Bow ASP Project is Moving Forward

– Sanctioning granted by Zargon’s Board on February 20, 2013.

– Approximately $6.5 million of capital was spent in 2012 to finalize design and procure major equipment.

– With this construction sanctioning decision, about $38 million of capital will be spent in 2013 to construct the facility and commence injection in January 2014.

• 2013 ASP Project Funding

– The 2013 ASP capital expenditures ($38 million) are expected to be funded from the sale of $20 million of non-strategic oil properties and the reallocation of $10 million of capital from conventional projects to the ASP project, with the remainder to be funded from existing bank lines.

• Cash Flows, Dividends and Maintenance Capital Balance (post 2013)

– Based on the reduced $40 million (from $50 million) conventional budget for 2013, oil production is now expected to average 5,000 bbl/d in 2013, a 3 percent decline on an oil production per share basis from Q4 2012 levels. Property sales in 2013 will further reduce conventional oil production volumes.

– With the ASP project constructed, annual sustaining conventional capital budgets of $45 million will be resumed in 2014.

• The ASP Prize

– Phases 1 and 2 of the Little Bow ASP project are forecast to produce an incremental 1,500 bbl/d by 2017; a level that will provide a per share compounded oil production growth rate (2013-2017) of 5 percent per year. Further oil production growth per share will come from Phases 3 and 4.

Net Asset Value Calculations

NAV Calculation (Dec 31, 2012)

Proved + Prob. McDaniel Est. (PVBT 10%) $ 473 million

Undeveloped 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)

(50)

0

50

100

150

200

250

Pre

miu

m (

Dis

cou

nt)

to

NA

V (

%) Source: Peters & Co. Limited, Intermediate & Junior Universe (March 18, 2013)

Zargon

Low Corporate Decline Rate and High PDP Reserves Allocation

Source: Peters & Co. Limited, Intermediate & Junior Universe (March 18, 2013)

0 20 40 60 80 100

Average Annual Decline Rate (%)

Average 32%

0 20 40 60 80 100

Proved Producing Reserves (% of P+P)

Average 34%

Zargon

Most Recent Production Guidance (February 2013)

• Oil and liquids:- Q3 2011 5,200 barrels per day (achieved with 5,330 bbl/d) - Q4 2011 5,400 barrels per day (achieved with 5,619 bbl/d) - Q1 2012 5,400 barrels per day (achieved with 5,496 bbl/d)- Q2 2012 5,350 barrels per day after allowing for property sales (achieved with 5,384 bbl/d)- Q3 2012 5,050 barrels per day (achieved with 5,079 bbl/d)- Q4 2012 5,100 barrels per day (almost achieved with 5,065 bbl/d)

- Q1 2013 updated 5,150 barrels per day - 2013 updated 5,000 barrels per day

• Natural gas: - Q3 2011 22.0 million cubic feet per day (achieved with 22.1 mmcf/d)- Q4 2011 21.6 million cubic feet per day (achieved with 22.0 mmcf/d)- Q1 2012 18.6 million cubic feet per day (achieved with 20.0 mmcf/d)- Q2 2012 18.6 million cubic feet per day (missed with 17.4 mmcf/d, due to shut-ins)- Q3 2012 16.5 million cubic feet per day (missed with 15.3 mmcf/d, due to shut-ins)- Q4 2012 15.5 million cubic feet per day (achieved with 15.9 mmcf/d)

- Q1 2013 updated 15.6 million cubic feet per day - 2013 updated 15.0 million cubic feet per day

• 2013 Capital Assumptions:- Field capital budget of $40 million focused on six quality non-ASP oil exploitation projects- ASP capital expenditures of $38 million to permit January 2014 ASP project start-up

• 2013 Cost Assumptions:- Operating Costs less than $16.50 per boe (includes transportation costs) - G&A Costs less than $4.50 per boe (excluding one time items)

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 60 percent maximum of estimated production volumes

– up to a maximum 30-month period

• Current Forward Oil Sales:

– H1 2013: 2,750 bbl/d at $98.89 US/bbl (WTI)

– H2 2013: 3,000 bbl/d at $97.06 US/bbl (WTI)

– H1 2014: 1,800 bbl/d at $94.63 US/bbl (WTI)

– H2 2014: 400 bbl/d at $90.90 US/bbl (WTI)

Key Takeaways at Current Share Price (March 11, 2013)

• Zargon’s oil exploitation business supports the current $0.06 monthly dividend while sustaining per share oil production (post 2013).

– Zargon has simplified its conventional business to focus on six long-life oil exploitation projects.

– During the 2013 “ASP heavy spend period” modest oil production per share losses will be incurred due to a reduced conventional capital budget and property sales.

– In 2014, a $45 million conventional capital program is forecast to maintain production per share.

• The Little Bow ASP project is forecast to provide an incremental 5 percent annual corporate oil per share growth rate for the 2013-2017 period.

– Little Bow phases 1-2 production rates are forecast to peak in 2018. Phases 1-4 peak rates are in 2020.

– Little Bow success will lead to significant follow-on projects at Little Bow and other Zargon properties.

• Zargon shares represent good value at the current share price of $7.34 per share.

– Investors buy Zargon at a discount to the proved developed producing year end 2012 “blowdown” net asset value of $7.75 per share (basic). No value is ascribed to a rich inventory of oil exploitation projects (neither booked undeveloped reserves or “unbooked potential” reserves).

– Compared to many of our peers on a net asset value basis, Zargon is inexpensive.

• Zargon provides a long dated call option on future oil prices and pays a 9.8 percent dividend in the interim.

– Downside is protected by a strong balance sheet and oil hedges (2,875 bbl/d at $97.94 US/bbl WTI in 2013).

– Low-decline oil production (particularly with ASP) underpins the dividend for many years.

WWW.ZARGON.CA

Corporate Presentation

March 20, 2013