zargon presentation (august 13) (rev...

zargon.ca

Corporate Presentation August 13, 2015

Forward Looking-Advisory

Forward-Looking Statements - This presentation offers our assessment of Zargon's future plans and operations as at August 13, 2015, 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, 2015 and beyond production and other guidance and the assumptions contained therein, estimated tax pools, Zargon’s reserve estimates, Zargon’shedging policies, Zargon’s drilling, development and exploitation plans and projects and the results there from and Zargon’s ASP project plans 2015 and beyond, strategic alternatives review process, the source of funding for our 2015 and beyond capital program including ASP, capital expenditures, costs and the results therefrom. By their nature, forward-looking statements are subject to numerous risks and uncertainties, some of which are beyond our control, including such as those relating to results of operations and financial condition, general economic conditions, industry conditions, changes in regulatory and taxation regimes, volatility of commodity prices, escalation of operating and capital costs, currency fluctuations, the availability of services, imprecision of reserve estimates, geological, technical, drilling and processing problems, environmental risks, weather, the lack of availability of qualified personnel or management, stock market volatility, the ability to access sufficient capital from internal and external sources and competition from other industry participants for, among other things, capital, services, acquisitions of reserves, undeveloped lands and skilled personnel. Risks are described in more detail in our Annual Information Form, which is available on our website. Forward-looking statements are provided to allow investors to have a greater understanding of our business.You are cautioned that the assumptions, including, among other things, future oil and natural gas prices; future capital expenditure levels; future production levels; future exchange rates; the cost of developing and expanding our assets; our ability to obtain equipment in a timely manner to carry out development activities; our ability to market our oil and natural gas successfully to current and new customers; the impact of increasing competition; our ability to obtain financing on acceptable terms; and our ability to add production and reserves through our development and acquisition activities used in the preparation of such information, although considered reasonable at the time of preparation, may prove to be imprecise and, as such, undue reliance should not be placed on forward-looking statements. Our actual results, performance, or achievement could differ materially from those expressed in, or implied by, these forward-looking statements. We can give no assurance that any of the events anticipated will transpire or occur, or if any of them do, what benefits we will derive from them. The forward-looking information contained in this presentation is expressly qualified by this cautionary statement. Our policy for updating forward-looking statements is that Zargondisclaims, 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 current reserve report has 17 proved plus an additional 13 probable undeveloped locations.

Low-decline conventional waterflood properties augmented by more than 35 prospective development locations not included in the reserve report.

High operatorship (~89%) characteristics.

High light/medium oil and liquids weighting (~81%).

Low production decline (~14% for oil and liquids).

Zargon Asset Character

ASPAssets(Little Bow)

Zargon Non-ASP assets

3

Tertiary Alkaline Surfactant Polymer Flood (“ASP”): Little Bow ASP tertiary recovery project provides years of oil production growth.

Ultimately (after the ASP flood becomes self-funding), these assets are well suited for a “sustainable income model”.

Core Areas

WillistonBasin

Alberta Plains South (incl.ASP project)

Alberta Plains North

Q2 2015 production of 1,741 bbl/d and 0.47 mmcf/d.

Proved and probable reserves of 7,930 mbbl and 1.23 bcf at Dec 31, 2014.

Proved and probable producing reserves of 7,022 mbbl and 1.20 bcf at Dec 31, 2014.

Exploitation upside includes 15 recognized and 25+ additional waterflood and water drive oil exploitation wells.

Q2 2015 production of 805 bbl/d and 2.45 mmcf/d.




Q2 2015 production of 1,174 bbl/d and 2.40 mmcf/d.



Includes Little Bow ASP project that brings very large long term oil upside.


4

Zargon Overview (August 11, 2015)

Capitalization– Toronto Stock Exchange: Symbols: ZAR; ZAR.DB– Common Shares Outstanding: 30.28 million (basic)– Market Capitalization: $67 million ($2.22 per share) (1)

– Net Debt at June 30, 2015: $112 million, comprised of

Convertible Debentures (6%) $57.5 million (face value – June 2017 maturity) Bank Debt and Net Working Capital Deficit $54 million Authorized Bank Debt $110 million (less than 50 percent drawn)

– Insider Ownership: 3.35 million shares (11 percent)

Dividend & Yield– Monthly Dividend: $0.01 per share– Yield at current share price: 5.4% (1)

Q2 2015 Production – Equivalent: 4,607 boe/d – Oil: 3,720 bbl/d (81% of production)– Gas: 5.32 mmcf/d

Q2 2015 Financial Results– Funds Flow from Operations $0.33 per basic share ($10.0 million)– Dividends Paid $0.09 per basic share ($2.7 million)

(1) Based on a monthly dividend rate of $0.01/share and using the August 11, 2015 closing share price of $2.22.

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.

Reported Q2 results of $0.33 per share funds flow and 4,607 barrels of oil equivalent per day.

2014 Year End Reserves

6

Strategic AlternativesReview Announced

February 19, 2015 Annual Reserves Review Press Release:

Proved and Probable Oil Reserves – 19.67 million barrels (13.0 year RLI),

Proved Developed Producing Oil Reserves – 10.05 million barrels (6.6 year RLI),

Proved and Probable NAV of $10.11 per share; Proved Developed Producing NAV of $3.84 per share (no ASP).

June 22, 2015 Banking Update:

Reflecting lower commodity prices, Zargon’s authorized bank line is reduced from $130 million to $110 million, of which more than $56 million remains undrawn.

Monthly dividend is reduced from $0.03 per share to $0.01 per share.

Revised Bank Line and Dividend

Waterflood/drive Well Inventory

Property Project Net Wells Comments

Bellshill Lake Increase fluid withdrawal 5+ Facility optimization; infills and step-outs

Killam Glauconite

Other Plains North

Develop Glauconite pool

Killam, Morinville, Carrot Creek

8+

4+

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, Midale, Weyburn, Ralph, Steelman, Mackobee

40+ Horizontal drainage wells in relatively tight reservoirs; additional pressure support required in some cases

Drilling Inventory of 65+ net wells.

Drilling activities have been curtailed as the Company has been allocating available capital to the Little Bow ASP project.

7

Long-Life, Low-Decline Oil Volumes

Using historical Zargon operated production plots, we calculate base oil production declines of 14%. Independent research by Peters (17%) and the proved and probable developed producing McDaniel analyses (1st year decline of 14.5%) support our view of industry-low base declines.

Comparative Declines Source: Peters & Co. Limited, Intermediates & Juniors (August 4, 2015) Oil sands and SAGD producers are not included.8

Zargon Corporate Decline Analysis ‐ Total Oil Production Rate

0

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‐14Gross W

.I. Oil Prod

uctio

n Rate ( bb

l/day )

2014 Additions2013 Additions2012 Additions2011 Additions2010 Additions2009 AdditionsBase 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 12.5%

0 10 20 30 40 50

Average Annual Decline Rate (%)

Average 29%

Zargon

Capital Budgets and 2015/16 Cash Flows

Based on the economic parameters outlined in the next slide, Zargon’s cash flow is anticipated to be greater than the forecasted capital and dividend ($0.01 per month) outlays for calendar 2016.

Should improved oil prices or production volumes provide additional cash flows, Zargon will allocate additional capital to conventional drilling opportunities and/or the Little Bow ASP phase 2 project.

Should reduced oil prices or production volumes result in substantially reduced cash flows, Zargon may suspend the remaining dividend and/or defer the Little Bow phase 1 ASP project by injecting only polymer until prices improve. This deferral action would reduce the ASP 2016 chemical costs by $10 million to $4 million and eliminate the ASP exploitation capital, taking the total 2016 capital budget down to $10 million.

Note: a $10 US/bbl WTI improvement in 2016 oil prices increases cash flows by $15 million (excluding hedges). 9

Capital Program 2015 Preliminary 2016

ASP Phase 1 Exploitation Capital (H1) $ 2 million $ 1 million

ASP Phase 1 Exploitation Capital (H2) $ 4 million $ 1 million

ASP Phase 1 Chemical Costs $13 million $14 million

Total ASP Capital $ 19 million $ 16 million

Conventional (non ASP) Capital $ 6 million $ 6 million

Total Capital Program $ 25 million $ 22 million

Production, Price and Cost Forecasts

Operating Oil - $23.00 per bbl (includes base ASP facility costs), Gas - $2.40/mcf; Incremental ASP Oil - $4.00/bbl

G&A $4.50 per boe (excluding one-time charges); declining per unit costs due to corporate downsizing and growing ASP volumes

Royalties Conventional Oil 14%; ASP Oil 5%; Natural Gas 8%

Conv. Oil Decline at 14% per year from Q2 2015 rate of 3,640 bbl/d

ASP Oil Use McDaniel 2P Forecast (refer to Slide 40 for more detail)

Gas Decline at 10% per year from estimated Q3 2015 rate of 5.0 mmcf/d

FX $0.78 US/$Cdn. WTI Oil Prices H2 2015 $50 US/bbl; $56 US/bbl in 2016

WTI to Zargon Base Differential; $17 Cdn./bblWTI to ASP Differential; $22 Cdn./bbl

Gas Prices $2.85 and $3.10/mmbtu AECO (2015 and 2016) less $0.25/mcf diff. Hedges Refer to next slide

Production Guidance

2015 Cost Targets(Year Avg.)

Other 2015 Parameters

10

Commodity Hedges

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

Hedging Strategy

Forward Oil Sales

11

July 2015: 1,000 bbl/d at $80.02 Cdn./bbl (WTI)

Aug – Dec 2015: 1,500 bbl/d at $79.78 Cdn./bbl (WTI)

H1 2016: 500 bbl/d at $79.30 Cdn.bbl (WTI)

McDaniel 2014 Yr. End Net Asset Value

Proved and probable conventional property value of $306 million less estimated December 31/14 net debt of $114 million leaves $192 million or $6.38 per Zargon share (30.09 million shares outstanding).

Little Bow ASP adds an additional $101 million, or $3.36 per share of proved and probable reserve value.

Waterflood & WaterdriveProperties

2015/Q2 Production McDaniel Reserves McDaniel

Oil (bbl/d)

Gas (mmcf/d)

Oil(mmbbl)

Gas (bcf)

PV10 Asset Value ($million)

Williston Basin 1,741 0.47 7.93 1.23 $ 150

Alberta Plains North 805 2.45 2.84 8.68 $ 63

Alberta Plains South 1,094 2.40 4.42 4.08 $ 93

Subtotal 3,640 5.32 15.19 13.99 $ 3062015/Q2 Production McDaniel Reserves McDaniel

Little Bow ASP AssetsOil

(bbl/d)Gas

(mmcf/d)Oil

(mmbbl)Gas (bcf)

PV 10 Asset Value ($million)

ASP Increment 80 - 4.48 1.70 $ 101

Grand Total 3,720 5.32 19.67 15.69 $ 407

12

Estimated Tax Pools

Category Dec. 31, 2014

Canadian Exploration Expense $ 58 million

Non Capital Losses $102 million

Canadian Development Expense $ 34 million

Canadian Oil & Gas Property Expense $ nil million

Canadian Undepreciated Capital Cost $ 83 million

Other $ 5 million

Total Tax Pools $282 million

13

At December 31, 2014, Zargon has more than $280 million of very high quality Canadian tax pools that will shield increasing ASP revenues for many years.

Directors and Officers

Craig H. Hansen

K. James Harrison

Kyle D. Kitagawa

Geoffrey C. Merritt

Board of Directors

Officers

14

Craig H. Hansen President and Chief Executive Officer

Leslie E. Burden Vice President, Land

Randolph J. Doetzel Vice President, Operations

Christopher M. Hustad Vice President, Alberta Plains South

Pete H.S. Janjua Vice President, Williston Basin

Brian G. Kergan Vice President, Corporate Development

Robert T. Moriyama Vice President, Enhanced Recovery

Jeffrey N. Post Chief Financial Officer

Jim Peplinski

Ronald C. Wigham

Grant A. Zawalsky

Key Takeaways

Zargon’s unique low-decline asset provides stability in this challenging low price period.

Bank debt (& net working capital deficiency) of $54 million at June 30, 2015 represents only 49% of 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 of the fundamental value inherent in the Company and that action must be taken to unlock this unrealized value.

Balance Sheet Protected

Strategic Process Initiated

Deep Discount to NAV

15

Investors buy Zargon at a large discount to the proved and probable net asset value (and to the proved developed producing net asset value) for Zargon’s waterflood and waterdrive oil assets.

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

Williston Basin

Williston Basin Activity Summary

Ongoing Activities Exploit long life low decline pools with horizontal wells and waterflood enhancements.

Estevan

North Dakota

Saskatchewan Manitoba

Haas

TruroMackobee Coulee

Frys

Steelman

Ralph

Elswick

Weyburn

Workman

17

Williston Basin Property Summary

Williston Basin assets are comprised of conventional oil projects located in Saskatchewan and North Dakota

The properties are characterized as waterflood and waterdrive systems with significant oil-in-place, low recovery factors, potential upside exploitation, exploration and development drilling opportunities

Average annual oil decline rate of 14%

18

Development Scope

Development wells 40+

Average development cost/well ~ $1.2 MM

Long-Life Oil Asset - Sustainability

19

Williston Basin Decline Analysis - Total Oil Production Rate

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Gro

ss W

.I. O

il Pro

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ion

Rat

e ( b

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2014 Additions2013 Additions2012 Additions2011 Additions2010 Additions2009 AdditionsBase Production

Data to M ay 31, 2015

0

200400

600800

1,000

1,2001,4001,600

1,8002,0002,200

2,4002,600

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Gro

ss W

.I. O

il Pro

duct

ion

Rat

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ay )

WB ProductionBase ProductionBase DeclineCombined Decline

Data to M ay 31, 2015

Established Primary Producing wells Decline is ~12%; Core Asset Base Decline ~14%

• Williston Basin portfolio are long-life assets in mature basins that exhibit low decline rates and long reserve lives

• Since 2010, these properties have provided $199 million of property cash flow and $83 million of free cash flow after capital, in addition to providing a net $89 million of proceeds from property dispositions

• In summary, assets are well positioned; Strong netbacks/cashflow, shallow decline rate and long-life core producing properties

Netback Elements

Oil Rate OPEX Netback Netback CAPEX Net A&D Net Proceeds

(bbl/d) ($/boe) ($/boe) ($M) ($M) ($M) ($M)

2010 2,840 13.82 43.12 46,365 29,707 16,561 33,219

2011 2,436 15.34 52.93 48,655 27,807 22,536 43,384

2012 2,163 16.00 44.90 36,730 19,637 36,203 53,296

2013 1,912 17.18 49.95 35,973 17,448 11,551 30,076

2014 1,731 20.71 46.91 30,858 21,153 1,700 11,405

Total 198,581 115,752 88,551 171,380

Ralph Midale - Twp 7, Rge 13 W2

• Established waterflood• Strong stratigraphic trap• Attic Oil• OIP ~25MMbbl• Current RF ~8%• Long life sustainable asset• Conventional horizontal infill

drilling opportunities• Waterflood optimization potential

Water Injection Wells

Direct Line Drive

PPUD

Ralph Waterflood Production Performance – Midale Beds

Primary Development

Secondary Development

20

Midale Huntoon - Twp 6, Rge 10 W2

21

• Large OOIP > 15-20+ MMbbl• Current RF 4-8%• Gross Land ~2.4 Section• Bypass Pay opportunities• Waterflood potential• Significant cumulative oil produced from

offset secondary recovery analogues• Enhance recovery - Potential to multi-stage

fracture stimulate the Midale/Vuggy interval with horizontal wells

• 15 potential horizontal drill locations

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R3W2R4R5

Steelman Operated Properties -Production

100% 640 acres undeveloped Midale

potential

Net Operated Frobisher and Midale Production ~450b/d Oil Net Non-Op Production ~140 b/d Oil

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

multi zone targets (Exploitation and Exploration)• Midale – Long life, sustainable production/cashflow

and low declines• Stratigraphic traps (Attic Oil) and strong structural

traps (Oil saturated, underlying natural water drive mechanism)

• 3D Seismic Coverage• Strong Netbacks and solid free cashflow generation• Infrastructure control and disposal capabilities

• Successful Waterflood in place - Steelman Voluntary Unit #8• Section 4 Twp 5 Rge 4 W2M potential waterflood candidate• Potential Waterflood Frobisher - State A producers• Strong Non-Op Assets ~WI 45%• Optimization opportunities• Extension of Midale trend - potential development

opportunities

Steelman – Midale WaterfloodTwp 5, Rge 4 W2

23

Section 4 Midale Oil Play• Attic Oil – Stratigraphic trap• Cum Oil produced 630 Mbbl• 7-4-5-4 W2M Water Injection pending

conversion• Implementation of secondary recovery;

waterflood to increase oil recoveries• Initiate Waterflood Q3/2015• Successful Offset Analogue

Sec. 2 Twp 5 Rge 4 W2M• Enbridge Autoship Unit Onsite • Gas Conservation

Section 2 Midale Oil Play• Established Waterflood• Attic Oil – Stratigraphic trap• OOIP ~9 MMbbl• Current RF ~15%• Enbridge Autoship Unit Onsite• Gas Conservation

Primary Development

Secondary Development

Steelman Midale Voluntary Unit No. 8Sect.2 Twp 5 Rge 4 W2M

Steelman MidaleSect.4 Twp 5 Rge 4 W2M

WINJ

North Dakota

24

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

Haas

Truro

Mackobee Coulee

zargon.ca

Alberta Plains North

Alberta Plains North Overview

Plains North assets are mainly comprised of oil projects in Alberta, from east central W4 to the Carrot Creek area

The properties are characterized as waterdrive or waterflood pressure supported systems with development drilling potential

Average annual oil decline rate of 14%

26

PropertyDevelopment

WellsAll In Cost/Well

($ thousands)

Bellshill Lake 5 $ 850

Killam Oil 1 $ 600

Killam Glauconite 8 $ 1,200

Morinville Leduc 2 $ 1,000

Carrot Creek Cardium 1 $ 1,300

Bellshill Lake

27

0

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 of 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

28

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

Morinville Leduc Property

29

• Zargon operated Leduc light oil project

• Existing battery with water disposal facilities in place

• Development potential for 2 infill oil wells defined on 3D seismic

Carrot Creek Cardium

30

• Unitized Cardium light oil waterflood projects (1 operated and 2 non-operated)

• Existing battery with water disposal facilities in place

• Single well infill development project with continuing optimization and reactivation

• Extensive 2D & 3D seismic coverage

0

10

20

30

40

50

60

70

80

90

2008 2009 2010 2011 2012 2013 2014 2015

W.I. Oil Rate (b

bl/day)

zargon.ca

Alberta Plains South

Alberta Plains South Overview

32

Taber - Conventional oil development with horizontal wells and waterflood

• Taber S – main Sunburst oil pools– Horizontal wells – Future drilling locations &

waterflood enhancement

• Taber SE – offsetting Sunburst oil development

• Glauconite Oil – Infill/Step-out drilling locations

Little Bow - ASP project and mature waterfloods

• Little Bow ASP Project – Current and Future Phases

• Little Bow/Retlaw Waterfloods -Optimization/Reactivations/Infill Drilling

Weighted average oil decline rate of 14%

PropertyDevelopment

WellsAll In Cost/Well

($ thousands)

Taber S (Hz) 5-7 $ 1,000

Taber SE (Hz) 3-6 $ 1,000

Little Bow (DD) 1-4 $ 750

Taber South – Sunburst OilHorizontal Development

33

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 OilProduction Growth

34 Data to April 2015

Taber South – Sunburst Hz OilOOIP and Recoveries

35

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

* McDaniel 2014 Year-End Reserves Report

Taber – Sunburst Oil – Project Areas

36

Taber SE – Sunburst Oil

Taber S – Sunburst Horizontal Development

zargon.ca

ASP Performance

Little Bow ASPEOR in a mature Southern Alberta Waterflood

Summary - Timeline

March 2014: ASP facility, oil battery and field construction complete and online ($50 million: construction & startup).

July 2014: Revised royalty program for Conventional Enhanced Oil Recovery (“EOR”) improves project economics. Phase 1 oil royalty of 5% for ten years confirmed by Alberta Energy in April 2015.

August 2015: ASP Injection: 5.1 million barrels- 23% of Phase 1 injection (ASP and polymer only)

Q3 2015: Although delayed, reservoir response provides conclusive evidence of oil bank formation. Zargon initiates $4 million (H2 2015 total) oil exploitation program to accelerate oil recovery.38

Capital Total to YE 2014: $ 62 million 2015 Optimization: $6 million (total) 2015 ASP Chemical: $13 million 2016 ASP Chemical: $14 million

Phases 1 & 2 Reserves: Zargon original forecast:

5.2 million barrels (12% doiip)

McDaniel evaluation: 4.5 million barrels (proved and probable) 1.5 million barrels (proved)

Phase 1 Response vs. Forecast

39

Jan 2015 July 2015 Jan 2016 July 2016 Jan 20170

200

400

600

800

1000

1200

1400

1600

1800

Oct-2014

bbl/d

Little Bow ASP Oil Production

Base Waterflood (McDaniel 2014 mid year & YE P+PDP)

Daily Production (to August 8, 2015)

McDaniel TP+P2015 /16 increment = 132 / 797 bbl/dUltimate: 2.45 million barrels

Sustained at this level for 2.5 years

June - August production impacted by injection lineoutages to be repaired by the end of September

2015-16 ASP Forecast Production

40

Period McDaniel YE 2014 Phase 1 Proved & Prob. (bbl/d)

Actual Production (bbl/d)

Q1 2015 4 50

Q2 2015 66 80

Q3 2015 164 -

Q4 2015 294 -

2015 Avg. 132 -

2016 Avg. 797 -

ASP project oil cuts have shown encouraging increases from 1.3 percent to 3.4 percent. The oil production response while evident, is delayed relative to original forecasts.

Prior to recent interruptions for injection pipeline repairs (related to material & installation defects on certain line segments), oil production trends have met the McDaniel “independent evaluator” forecast which assigns a total of 4.5 mmbbl of proved and probable reserves to Phases 1 and 2 of the Little Bow ASP project.

In July, Zargon has commenced a $4 million remedial and optimization program (2015 H2) to accelerate oil production.

Little Bow ASP: Phase 1 Production

Despite encouraging oil cut improvements, oil production growth “stalled” in Q2

Oil cut improvements were offset by losses in well productivity

Fluid production impacted by:

– ASP response: higher viscosity fluids

– Injection pattern re-configuration

– Injection line outages: June-Sept. 2015

2015 H2 program optimization and remedial progam will:

– Optimize injection rate and locations (improved balance throughout pool)

– Drill infill producers to increase production capability & reduce well spacing

– Optimize ASP injectant formulation

• Increase Surfactant concentration

0

1

2

3

4

5

6

7

0

50

100

150

200

250

300

350

Oct Nov Dec Jan Feb Mar Apr May Jun Jul Aug SepO

il Cut (%

)OIl

(bpd

)

Little Bow ASP: Phase 1 Production

Oil Rate Oil Avg. Oil Cut Oil Cut Avg.

2014 2015

Production Data to: August 08, 2015

0

2,000

4,000

6,000

8,000

10,000

12,000

14,000

16,000

18,000

20,000

Oct Nov Dec Jan Feb Mar Apr May Jun Jul Aug Sep

Flui

d Pr

oduc

tion

(BPD

)

Fluid Production

2014 201541

Phase 1 Northern Region

Northern Region

Chemical injection: 24% complete

Prior injection conformance challenges resolved

Summer/fall work program: producer workovers

Current production impacted by June/July injection line breaks (to be restored by the end of September)

Encouraging increases in oil cuts from 1% to 4.5%

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1

2

3

4

5

6

7

8

9

10

-250

-200

-150

-100

-50

0

50

100

150

200

250


Oil C

ut (%)

Oil

(bbl

/d)


2014 2015

Northern Region Production

01,0002,0003,0004,0005,0006,0007,0008,0009,000


Tota

l Flu

id (B

PD

)

2014 201542

01,0002,0003,0004,0005,0006,0007,0008,0009,000


Tota

l Flu

id (B

PD

)

Phase 1 Central Region

0

1

2

3

4

5

6

7

8

9

10

-250

-200

-150

-100

-50

0

50

100

150

200

250


Oil C

ut (%)

Oil

(bbl

/d)


2014 2015

Central Region Production

Central Region

Chemical injection 18% complete

Currently under-injected – Summer fall work program:

Drill one ASP injector and two producers

Convert one producer to ASP injector

Encouraging increases in oil cuts from 1% to 3%

Current production impacted by June/July injection line breaks (to be fully restored by end of September)

2014 201543

Phase 1 Southern Region

0

1

2

3

4

5

6

7

8

9

10

-250

-200

-150

-100

-50

0

50

100

150

200

250


Oil C

ut (%)

Oil

(bbl

/d)


2014 2015

Southern Region Production

Southern Region (gas cap area)

Chemical injection: 27% complete

First area to show response. Oil cut now static

Fluid production reduced: Injection to be re-configured to improve oil cut and production

Summer/fall work plan: - Add one ASP injector (convert water injector) - Injector/producer workovers

01,0002,0003,0004,0005,0006,0007,0008,0009,000


Tota

l Flu

id (B

PD

)

2014 201544

Phase 1: 2015 H2 Optimization

45

Item

Production

Drill 2 new oil producers

Improved downhole equipment (pumps & tubulars) to improve operating efficiencies

Scale inhibition: chemical and electromagnetic technology

Recompletions

Injection

Drill 1 ASP Injection Well

Convert 1 Oil Producer to ASP Injector

Convert 1 Waterflood Injector to ASP Injector

Injector Stimulations and Recompletions

ASP Fluid Design

Increase Surfactant Concentration

zargon.ca

ASP Background

Canadian ASP Projects

10 Canadian ASP Projects in operation.

2 additional projects have regulatory approval.

Major operators: Husky, CNRL, Cenovus, Crescent Point.

Significant implementation in Saskatchewan: historically (no longer) favorable EOR royalty treatment.

Technology utilized since 1980’s.

47

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.

RockRock

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

b) Alkali / SurfactantMobilizes trapped oil

Water Injection

TrappedOil Droplet Water

RockRock

Mobilized Oil DropletAlkali & SurfactantSolution

Injector Producer

WaterWater

Injector Producer

PolymerSolution

IncreasedContactVolume

PolymerSolution

IncreasedContactVolume

a) Water Injection b) Polymer Injection

Surfactants: Detergent; mobilizes trapped oil

Alkali: Increases surfactant effectiveness

Polymer (Thickener):Thickened water helps sweep oil from the reservoir

48

ASP Injection Sequence

1) ASP InjectionA blend of Alkali, Surfactant & Polymer mobilizes trapped oil

2) Polymer “Push”Polymer displaces mobilized

oil to producing wells

3) Terminal WaterfloodReturn to waterflood to

complete oil displacement

OIL BANK ASP POLYMER WATER

49

Little Bow Phase 1 & 2 Injection Schedule

Phase 1 ASP Polymer Waterflood

Phase 2 ASP Polymer

2013 2014 2015 2016 2017 2018 2019 2020 2021

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)50

Taber Production HistoryMay‐14

May‐13

May‐12

May‐11

May‐10

May‐09

May‐08

May‐07

May‐06

8% R F 10% R F 12% R F 14% R F 16% R F

8% R F 10% R F 12% R F 14% R F 16% R F10

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 Prod

uctio

n (bbl/d)

1

10

100

1,000

Oil Cut (%)

Data to December 2014

Oil Cut (%)

First ASP InjectionMay, 2006

AER DPIIP = 43.1 mmbblASP Recovery Pool Rec*

Percent mmbbl Mmbbl8% 3.4 20.510% 4.3 21.312% 5.2 22.214% 6.0 23.016% 6.9 23.9

* Recovery where ASP flood returns to pre‐ASP levels

Phases 1-4 Original 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)

51

15‐19W4 15‐18W4

14‐19W4 14‐18W4

Zargon LandZargon 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 WaterfloodPhase 2 ASP Polymer Waterflood

Phase 3 ASP Polymer WaterfloodPhase 4 ASP Polymer

2022 2023 2024 20252020 2021 2026 20272013 2014 2015 2016 2017 2018 2019

ASP Phase 1 & 2 Performance History

• ASP injection commenced April 2014 (just in the Phase 1 area)

• Facility, injection and well optimization will improve oil production rate

• Increasing oil cut confirms the positive impact of ASP on reservoir recovery52

Phase 1&2 Area

ASP StartupApr/2014

Little Bow ASP: Phases 1&2 Production

0

500

1000

1500

2000

2500

2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030

bbl/d

Phases 1 & 2 Model Economics at $75 WTI

WTI Price: $75 US/bbl RealUS Exchange: 0.85 $/$Field Oil Price: WTI / US Exchange less $22 Cdn/bblZargon Internal Production ForecastsEffective Date for “Go Forward” Economics: January 1, 2015

53

(1) ASP Chemical injectant booked as capital(2) Phase 2 capital; incurred in 2016

Full Cycle Go Forward

IRR (%) 14 61

PV10 (million) $ 30 $101

F&D ($/bbl) (1) 30 18

Netback ($/bbl) (1) 57 58

Recycle Ratio (1) 1.9 3.2

Oil Reserves (mbbl) 5,200 5,200

Development Capital (million) (2) $ 62 $ 12

Chemical ($million) $ 83 $ 71

Phases 1&2: 12% Recovery (5.2 mmbbl)

Phase 1

Phase 2

Base Waterflood

Phases 1&2 Price SensitivitiesWTI:

Full Cycle Go Fwd. Full Cycle Go Fwd.IRR (%) 19 86 24 117

PV10 (million) $67 $138 $104 $176

$85 US/bbl $95 US/bbl

ASP Development Forecast - Phases 1-4

0

500

1000

1500

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2500

3000

2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030

bbl/d

Zargon W.I. Production

Phases 3 & 4 Model Economics at $75 WTI

WTI Price: $75 US/bbl Real; US Exchange: 0.85 $/$Field Oil Price: WTI / US Exchange less $22 Cdn/bblZargon Internal Production ForecastsEffective Date for “Go Forward” Economics: January 1, 2015Reflects Current Zargon Working Interests varying from 97 – 100 %

54

(1) ASP Chemical injectant booked as capital(2) Phase 3 & 4 capital; incurred in 2019-2021(3) Phase 3 & 4 chemical costs; incurred in 2018-2027

Phases 1&212% Recovery

100% W.I.

Phases 3&411% Recovery

97% W.I.

Base Waterflood

Go Forward Economics

Phases 3 & 4 Phases 1 ‐ 4

IRR (%) 33 55

PV10 (million) $ 50 $150

F&D ($/bbl) (1) 22 20

Netback ($/bbl) (1) 62 60

Recycle Ratio (1) 2.8 3.0

Oil Reserves (mbbl) 4,650 9,850

Development Capital (million) (2) $ 20 $ 32

Chemical (million) (3) $ 86 $154

Phases 1-4 Price SensitivitiesWTI:

Phases 3&4 Phases 1-4 Phases 3&4 Phases 1-4IRR (%) 41 79 49 110

PV10 (million) $71 $210 $93 $269

$85 US/bbl $95 US/bbl

Alberta Modified EOR Crown Royalty

Program Highlights and its Impact on Zargon

Announced July 2014 - Alberta conventional oil EOR royalties in line with Alberta oil sands and Saskatchewan conventional oil EOR programs.

5 percent oil royalty rate for up to 10 years.

Little Bow Phase 1: Ten year approval was received from Alberta DOE in April 2015.

McDaniel update includes the new EOR royalty program provisions.

McDaniel (Phase 1 and 2)Oil & Liquids

Reserves(mmbbl)

Project NPVPrev. EOR Roy.

As of Jan. 1, 2014($million)

Project NPVModified EOR Roy. As of July 1, 2014

($million)

Proved Undeveloped 1.53 25.1 39.6

Proved and Probable Undeveloped 4.48 66.3 98.6

55

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