zargon - q3 release - november 6 (rev 3a)zargon.ca/wp-content/uploads/2012/02/zargon-q3... ·...

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Corporate Presentation

Q3 2012 Results

November 7, 2012

Advisory – Forward-Looking Information

Forward-Looking Statements - This presentation offers our assessment of Zargon's future plans and operations as at November 7, 2012, 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.

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.

Highlights(As at November 7, 2012 unless otherwise stated)

• Listed on Toronto Stock Exchange: Symbols: ZAR; ZAR.DB

• Common Shares Outstanding: 29.78 million (basic)

• Market Capitalization: $252 million

• Annualized Q4 2012 Dividend: $0.72/share (8.5% yield) (1)

• Q3 2012 DRIP Participation Rate: 13%

• Q3 2012 Oil Production Weighting: 67%

• 2P Reserves (Dec. 31/11): 34.3 million boe (RLI: 10.1 years)

• Net Undev. Land (September 30/12): 361 thousand acres

• Net Debt (September 30/12): $99 million (including debenture)

• Unutilized Bank Lines (September 30/12): $120+ million

(1) Based on a revised 2012 fourth quarter monthly dividend rate of $0.06/share and using the November 6, 2012

closing share price of $8.45.

Financial & Operational Highlights(Quarter ended September 30, 2012)

• Q3 2012 Financial Highlights

• Funds flow – $14.4 million

• Dividends – $7.8 million net of the DRIP

• Capex – $10.4 million, including $1.8 million of ASP capital

• Q3 2012 Production Highlights

– Average Production 7,634 boe/d

• Oil: 5,079 bbl/d (67% of production)

• Gas: 15.33 mmcf/d

• September 30, 2012 Tax Pools of $303 million (> 40% CEE or non capital losses)

– Canadian operations expected to be tax free through at least 2016

• Year End 2011 Reserves (effective December 31, 2011)

– McDaniel Proved and Probable Reserve Estimate (76% developed producing)

• Oil & Liquids: 24.1 mmbbl (11.7 year reserve life index)

• Gas: 61.4 bcf (7.7 year reserve life index)

• Equivalent: 34.3 mmboe (70% oil and liquids)

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 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.

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 35% of cash flow and should not significantly exceed 50% of cash flow for an extended period of time.

Risk Management

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

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.

History of Returns

• Since inception, Zargon has returned $16.34 per share ($315 million) of dividends and distributions to shareholders.

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

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 opportunities130+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

2013-15 high-graded program will promote strong returns (25 net wells per year)

75

Undrained seismically defined horizontal targets15+Frobisher Structure

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

40+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 Project Oil Production and Dividend Sustainability

Oil Production Sustainability (before ASP growth):

Oil production (per share) is expected to be maintained 2013 through 2015 from our existing non-

ASP project inventory, based on the following assumptions:

$50 million annual field capital program; annually 25 wells high-graded from 115+ well

inventory (excluding ASP).

21% corporate average oil production decline rate.

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

Dividend Sustainability:

The $0.06 monthly dividend is expected to be maintained through 2015 without property sales or

an increase in net debt, based on the following assumptions:

$85 Cdn. per barrel average FOB Edmonton oil price (2013-15).

$3.85 Cdn. per mmbtu average AECO natural gas price (2013-15).

$20.50 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.

Production Guidance (November 7, 2012 Press Release)

• 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 revised 5,100 barrels per day (exit rate of 5,400 bbl/d)- 2013 first look 5,400 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 revised 15.5 million cubic feet per day (exit rate of 16.5 mmcf/d)- 2013 first look 15.5 million cubic feet per day

• 2013 Capital Assumptions:- Field capital budget of $50 million focused on six quality non-ASP oil exploitation projects- ASP capital expenditures of $37 million to permit December 2013 ASP project start-up

• 2013 Cost Assumptions:- Operating Costs less than $16 per boe (includes transportation costs) - G&A Costs less than $4.50 per boe (excluding one time items)

Net Asset Value Calculation (2011 Year End)

NAV Calculation (Dec 31, 2011)

Proved + Prob. McDaniel Est. (PVBT 10%) $ 559 million

Undeveloped Land $ 33 millionDeduct Net Working Capital & Bank Debt - $ 109 million Net Asset Value $ 483 million

Zargon Proved + Prob. Net Asset Value $16.45 per share

10.56310386PDP

13.90408484P+PDP

16.45483559Proved & Prob.

11.44336412Total Proved

Net Asset Value

($/share)

Net Asset Value

($ million)

McDaniel PVBT 10%

($ million)Reserve Category

(McDaniel January 1, 2012 price forecast and 29.36 million basic Zargon shares as of December 31, 2011)

Zargon Year End NAV

Peters’ Market Cap Comparison to NAV

(50)

0

50

100

150

200

250

300

350

400

Pre

miu

m (

Dis

cou

nt)

to

NA

V (

%)

Companies

Peters & Co. Limited, Intermediate & Junior Universe (November 5, 2012)

Zargon

Hedging Strategy 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:

– Q4 2012: 2,500 bbl/d at $99.92 US/bbl (WTI)

– H1 2013: 2,350 bbl/d at $99.57 US/bbl (WTI)

– H2 2013: 1,800 bbl/d at $98.20 US/bbl (WTI)

– H1 2014: 400 bbl/d at $97.05 US/bbl (WTI)

Key Takeaways at Current Share Price (November 6, 2012)

• Zargon oil exploitation business provides considerable upside.

– Zargon has simplified its business to focus on the exploitation of seven profitable oil projects.

• Hamilton Lake, Killam, Bellshill Lake, Taber, Williston Basin (Midale, Frobisher) provide a multi-year inventory of profitable oil exploitation projects.

– These six exploitation projects are economic to pursue at considerably lower oil prices.

• The Little Bow ASP project provides long-life reserves for Zargon.

– 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.

– Investors buy Zargon at a 20% discount to the proved developed producing year end 2011 “blowdown” net asset value of $10.56 per share (basic). No value is ascribed to a rich inventory of oil exploitation projects (neither booked undeveloped reserves or “unbookedpotential” reserves.)

• Zargon provides a long dated call option on future oil prices and pays an 8+ percent dividend in the interim.

– Downside is protected by a strong balance sheet and WTI oil hedges.

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

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Appendix A: Six Conventional Oil Exploitation Projects

Oil Exploitation Project Review

• Six active project areas in three exploitation teams

– Alberta Plains South

• Taber Sunburst Waterflood Exploitation project

– Alberta Plains North

• Bellshill Lake Development & Optimization

• Hamilton Lake Viking project

• Killam Glauconite Project

– Williston Basin

• Frobisher Horizontal development

• Midale Drainage

• Development of type curves for each project

– Derived from all Zargon 2010 and 2011 drilling results with actual well performance to October 2012

• Cash flow analysis based on $85 CDN per barrel FOB Edmonton par price and historical field differentials

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 / 1Taber Sunburst

$ 44,000$ 20.500.16416261$ 286 $ 1,80050+ / 0Hamilton Lake Viking [2]

$ 27,000$ 12.901.37528675$ 1,919$ 1,400Optimized Target Well .

$ 50,000$ 16.500.51274258$ 680 $ 1,35010 / 3Killam Glauconite - Primary

$ 42,000$ 15.900.87406075$ 1,450$ 1,680Target Waterflood Well [3]

40+ / 2

15+ /1

Pot’l/

Booked

Wells

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

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

Production [1]

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) [4]

CAPEX

($M)Project Name

Notes: [1] based on mid-year rate

[2] cost & productivity upside

[3] waterflood capital of $325M included

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

Alberta Plains North Orientation Map

Jarrow

Bellshill Lake

Hamilton Lake

Killam Glauc

StettlerProvost

Camrose

Wainwright

Alberta Plains NorthViking Oil Drilling Activity (2007 to 2012)

• In the greater Hamilton Lake

area since 2007, nearly 300

multi-frac horizontal wells have

been drilled targeting the Viking

formation

• In the last two years, Zargon has

drilled five longer reach Viking

horizontal wells using ball and

seat technology. Results were

varied, but on average the wells

will recover 60 mbbl of oil

reserves

• In Q4 2012, Zargon drilled four

Viking horizontal wells using

monobore and frac sleeves

technologyHamilton Lake

Jarrow

Bellshill Lake

Killam Glauc

Viking Oil Wells drilled since 2007

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

Q4/2012 Horizontal MultiFrac Test WellsZargon HZ Wells

3 Wells planned for 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 5 multi-frac horizontal wells

Hamilton Lake Viking Oil UnitProduction History of the Viking Unit

• The Hamilton Lake Oil Unit waterflood was prematurely suspended in the 1980’s with less than a 10 percent reservoir recovery

• Our reservoir modeling suggests that significant reserves additional can be recovered with multi-frac horizontal well technology

0

1,000

2,000

3,000

4,000

5,000

0 5,000 10,000 15,000 20,000

Cumulative Oil Produced ( Mbbl )

Oil

Pro

du

ctio

n R

ate

( b

bl/

da

y )

0%

10%

20%

30%

40%

50%

60%

70%

80%

90%

100%

Oil

Cu

t (

% )

Viking C

Viking B

15.9434222Jul-12

15.8926167Dec-11

15.862861Dec-10

Cum Oil

(MMbbl)

Oil Cut

(%)

Oil Rate

(bbl/d)

Hamilton Lake Viking Oil UnitProduction History Including Recent HZ Wells

10

100

1,000

10,000

1965 1970 1975 1980 1985 1990 1995 2000 2005 2010

Oil

Pro

du

ctio

n R

ate

( b

bl/

da

y )

Production restored to early 1990's levels

Hamilton Lake Viking - Productivity Implications Horizontal Well Orientation, Fracture Optimization

• Horizontal well with a NE to SW orientation

‒ fracture stimulation follows approximately along

the length of the horizontal section and has

resulted in reduced reservoir contact with lower

than expected productivity.

• Horizontal well with a NW to SE orientation

‒ fracture stimulation is expected perpendicular to

the length of the horizontal section which is

expected to improve initial productivity and also

ultimate recovery.

Water Injector

Dominant Induced Fracture Direction

Waterflood swept area

Partially Swept Oil

Current Zargon HZ Oil Wells

Q3/2012 Proposed HZ Wells

Legend

N

Wat

er in

ject

ion fr

actu

re o

rienta

tion

Water channels between

injectors & producers

• Production history shows that water injection has

trended NE to SW between injectors, leading to early

water breakthrough in vertical oil producers, resulting

in low overall recovery.

Hamilton Lake Viking Oil UnitHistoric Well Performance & Type Curve

Well Production History Dataset Average Type Curve Target Well

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

)

Target Well

-500

0

500

1,000

1,500

2,000

2,500

3,000

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 )

Hamilton Lake Viking - Primary Depletion Type Curve Evaluation

Hamilton Lake Viking Oil Unit Historical Results under Three Pricing Scenarios

6230 day rate (bbl/d)

61Reserves - Oil (Mbbl)

165- Gas (MMcf)

44,000Efficiency ($/bbl/d)

20.50F&D ($/BOE)

0.16P.I.R. @ 10%

4.2Payout (yrs)

16%IRR (%)

416 Month Rate (bbl/d)

88Total (Mboe)

$ 286PV10 ($M)

$ 1,800CAPEX ($M)

Analysis Using Base Pricing

2013 “Base Price”

Edm. Light $85.00/bbl

Field Price $79.00/bbl

• Target well based on improved costs and slightly higher rates

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

Target Well

Ba

se P

rice

Target Well: IP30 90 bbl/d, 75 Mbbl oil, $1.4 MM capital

OPEX ($/bbl) $ 13.50

Target OPEX ($/bbl) $ 9.00

H2H Pool

Bellshill LakeStable Oil Production from Exploitation

10

100

1,000

2005 2006 2007 2008 2009 2010 2011 2012

We

lls

( #

)

O

il R

ate

( b

bl/

d )

1,000

10,000

100,000

Flu

id R

ate

( b

bl/

d )

Optimization &

Infill Drilling

Bellshill Optimization

- Battery expansion (complete)

- Leduc water disposal well (complete)

- Doubling of battery fluid capacity

2012 Q3 - Q4 Program

- 3 hz re-entry candidates, 1 vertical location

Bellshill LakeHistoric Well Performance & Type Curve

Bellshill Lake - Development & Optimization

1

10

100

1,000

00

-01

00

-02

00

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00

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00

-06

00

-07

00

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00

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00

-10

00

-11

00

-12

01

-01

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-02

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-03

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-04

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-06

01

-07

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-08

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-10

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-11

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-12


Fie

ld E

stim

ate

d D

ail

y O

il P

rod

uct

ion

( b

bl/

da

y )

Well Production History Dataset Average Type Curve

Bellshill Lake Historical Results under Three Pricing Scenarios

4530 day rate ( bbl/d)


8.00F&D ($/BOE)

2.82P.I.R. @ 10%

0.8Payout (yrs)

500%IRR (%)


51.0Reserves - Oil (Mbbl)

$ 1,105PV10 ($M)

$ 400CAPEX ($M)


0

500

1,000

1,500

2,000

60 65 70 75 80 85 90 95 100 105 110


Be

fore

Ta

x D

CF

@ 1

0%

( $

M )

Bellshill Lake - Well ReEntry Type Curve Evaluation

Ba

se P

rice

OPEX ($/bbl) $ 9.20




• Bellshill Lake has good economic returns with some further re-entry drilling potential

Killam Glauconite Oil ProjectWaterflood Project Development Candidate

26 Degree API sweet crude

Zargon drilled 7 Hz producers

100% WI in four sections

Significant waterflood upside

1

10

100

1,000

2005 2006 2007 2008 2009 2010 2011 2012

Oil

Ra

te (

bb

l/d

)

Future Development Oil Wells

Future Infill Water Injection Wells

Killam Glauconite Waterflood CandidatePilot Waterflood Project - Phase 1 & 2 Scope

• Pilot waterflood application

was approved by ERCB

review in Sept, 2012

• Water injection expected to

commence by March 2013

06-15 WSW &

Battery

13-15 InjPhase 1 Scope

Phase 2 Scope

Killam Glauconite Oil Project Historic Well Performance & Type Curve

Well Production History Dataset Average Type Curve Target Well

Killam Glauconite - Oil Project

1

10

100

1,000

00

-01

00

-02

00

-03

00

-04

00

-05

00

-06

00

-07

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-08

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-10

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-11

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-12

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-01

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-05

01

-06

01

-07

01

-08

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-09

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-10

01

-11

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-01

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-02

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-03


Fie

ld E

stim

ate

d D

ail

y O

il P

rod

uct

ion

( b

bl/

day

)

Primary Depletion Performance

Target Waterflood Well

Killam Glauconite Oil Project Historical Results under Three Pricing Scenarios



140- Gas (MMcf)


16.50F&D ($/BOE)

0.51P.I.R. @ 10%

2.5Payout (yrs)

34%IRR (%)


82Total (Mboe)

$ 680PV10 ($M)

$ 1,350CAPEX ($M)


OPEX ($/bbl) $ 16.85




• Waterflood potential is the key to value in the Killam Glauconite project

• Proceeding with a pilot project to test the waterflood

-500

0

500

1,000

1,500

2,000

2,500

60 65 70 75 80 85 90 95 100 105 110


Be

fore

Ta

x D

CF

@ 1

0%

( $

M )

Killam Glauconite Project - Primary Depletion Type Curve Evaluation

Ba

se P

rice

Target Waterflood Well

Target Well: IP30 60 bbl/d, 75 Mbbl oil, $1.68 MM capital

Alberta Plains South Orientation Map

Little Bow

Taber

Grand ForksRetlaw

Lethbridge

Taber

Enchant

Vauxhall

Taber South Sunburst Hz Oil Development

2012 Activities

• Expand Horizontal Waterflood

‒ Improve injectivity of existing wells

‒ Convert 02/06-01 hz to injection

• Recently finished drilling 2 hz. oil wells

Forecast 2013 Activities

• Drill 2-3 more horizontal wells

• Convert an additional well to water injection

• Increase water handling capacity at 14-11 battery

Future Activities

• Drill 5-7 more wells

• connect batteries 14-11 & 15-36 to further optimize waterflood, and expand injector count as required

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 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


Fie

ld E

stim

ate

d D

ail

y O

il R

ate

( b

bl/

day

)


Taber South Historical Results under Three Pricing Scenarios



11.00F&D ($/BOE)

2.24P.I.R. @ 10%

0.9Payout (yrs)

153%IRR (%)



$ 2,450PV10 ($M)

$ 1,100CAPEX ($M)


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


Be

fore

Ta

x D

CF

@ 1

0%

( $

M )

Taber Sunburst Oil Project - Type Curve Evaluation

Ba

se P

rice

OPEX ($/bbl) $ 8.00




• The recently implemented waterflood is having a positive impact on production

• Further drilling and expansion of the waterflood area are warranted

Williston Basin Orientation Map

Estevan

North Dakota

Saskatchewan Manitoba

Haas

Truro

Mackobee Coulee

Frys

Steelman

Ralph

Elswick

Weyburn

Workman

Steelman (Frobisher Zone) Production Growth from Recent Drilling Programs

Production Contribution by Drilling Program Date

10

100

1,000

2007 2008 2009 2010 2011 2012

Oil

Ra

te (

bb

l/d

)

Pre 2008 2008 2009 2010 2011

Cumulative Oil Production to May 2012 of 945 Mbbl

Gross Area Production Additions

Frobisher ProgramHistoric Well Performance & Type Curve

Williston Basin - 2010 and 2011 Frobisher Drilling Results

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

01

-04

01

-05

01

-06

01

-07

01

-08

01

-09

01

-10

01

-11

01

-12

02

-01

02

-02

02

-03

02

-04

02

-05

02

-06

02

-07

02

-08

02

-09

02

-10

02

-11

02

-12


Fie

ld E

stim

ate

d D

ail

y O

il P

rod

uct

ion

( b

bl/

da

y )


Frobisher ProgramHistorical Results under Three Pricing Scenarios



15.00F&D ($/BOE)

2.02P.I.R. @ 10%

0.5Payout (yrs)

388%IRR (%)


84.0Reserves – Oil (Mbbl)

$ 2,495PV10 ($M)

$ 1,240CAPEX ($M)


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


Be

fore

Ta

x D

CF

@ 1

0%

( $

M )

Williston Basin Structural Project (Frobisher) Type Curve

Ba

se P

rice OPEX ($/bbl) $ 9.85




• Frobisher wells are prolific with high initial decline rates, but eventually stabilizing

• Economic returns are excellent and the wells have a long producing life

Midale ProgramHistoric Well Performance & 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


Fie

ld E

stim

ate

d D

ail

y O

il P

rod

uct

ion

( b

b/d

l )

Midale Program Historical Results under Three Pricing Scenarios



17.60F&D ($/BOE)

1.14P.I.R. @ 10%

2.4Payout (yrs)

45%IRR (%)


75.0Reserves – Oil (Mbbl)

$ 1,493PV10 ($M)

$ 1,320CAPEX ($M)


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


Be

fore

Ta

x D

CF

@ 1

0%

( $

M )

Williston Basin Drainage Project (Midale) Type Curve

Ba

se P

rice OPEX ($/bbl) $ 7.00




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

• Economic returns are excellent and the wells have a long producing life

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Appendix B: Little Bow Alkaline Surfactant Polymer (“ASP”) Tertiary Recovery Project

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

Battrum (Hyak Energy)

Little Bow (Zargon)

Taber (Husky)

Strathmore (Terrex)

Suffield (Cenovus)

Mooney (Black Pearl Resources)

Instow (Talisman)

Edmonton

Lethbridge

Calgary

Medicine Hat

Grande Prairie

Grand Forks

(CNRL)

Gull Lake ( Husky)

Fosterton (Husky)

Coleville (Penn West)

In Progress

Scheme Approved

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

Southern AlbertaASP Project Orientation (Zargon Little Bow & Husky Taber Analogy)

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

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

Little Bow Mannville “I” & “P” And Taber Mannville “B” Similar

Reservoir Characteristics

• Potential ASP project reservoirs are limited - based on reservoir and fluid properties

• Taber Mannville “B” and Little Bow are close analogs

Taber Little Bow ASP Screening

Lithology Sandstone Sandstone Sandstone �API Oil Gravity 19 21 > 15 �Mean Depth (ft) 3,226 3,555 < 6000 �

Average Permeability (mD) 1,000 900 > 100 �Reservoir Temperature ( °F) 88 91 < 180 �

Viscosity (cp) 40 21 < 200 �Successful Waterflood Yes Yes Yes �

Average Porosity (%) 25 23 > 15 �Original Pressure (psia) 1,134 1,615

Net Pay (ft) 23 37

Initial Water Saturation (%) 22 21

Little Bow Mannville “I” and “P” Pools

Zargon Land

Zargon Wells

“MM” Unit

“C8C / X8X” Pool

“U&W” Unit

Little Bow “I” Pool

Little Bow “P” Pool

Alberta

Little Bow

Alberta

Little Bow

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

Taber Mannville B – Continued Strong Performance

Taber Mannville “B” - ASP 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 ASP Development: Phase 1&2

• Phased development approach for Little Bow and future pools

• ASP facilities designed for multi-phase development

• Little Bow developed in two overlapping

ASP/Polymer cycles

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 Phases 1 and 2 Injection Schedule

Phase 1 ASP Polymer Waterflood


2013 2014 2015 2016 20212017 2018 2019 2020

Little Bow ASP Oil Recovery: Phase 1&2

• Incremental oil rate peaks in excess of 1,500 bopd in 2017

• McDaniel Year End 2011 Evaluation

– 3.7 mmbbl Oil

– 4.15 mmboe

– Probable Undeveloped

Little Bow ASP Production: Phases 1 & 2

0

200

400

600

800

1000

1200

1400

1600

1800

2000

2012 2014 2016 2018 2020 2022 2024 2026 2028 2030

BO

PD

Base Phase 1 Phase 2

12% Recovery

4.4 mmbbl

Phase 1

Phase 2

Base Waterflood

Little Bow ASP Facility Site

• Travers gas plant acquisition completed July 2012

• ASP Facility relocated to open area south of Gas Plant

• Pipeline relocation and aggregation no longer required

• Plot Plan Optimization

– More compact footprint

– Phase 2 expansion considerations

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

Future Little Bow ASP Facility

Little Bow ASPProcess Overview

Water

Softening

Water

De-oiling

Injection

ASP Fluid

Blending

Little Bow ASPCapital Costs (non-Chemical)

• “As spent” dollars

• Unit cost: 13.36 $/bbl Oil

Phase 1 Phase 2 Total

($MM) ($MM) ($MM)

ASP Facility 32.3 1.7 34.0

Battery 9.2 3.2 12.4

Pipelines 1.5 3.2 4.7

Water Disposal/Source 1.5 0.0 1.5

Subsurface/Surface 3.0 4.2 7.2

47.5 12.3 59.8

Little Bow ASP - Phase 1&2

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

-40

-30

-20

-10

0

10

20

30

40

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

illio

ns

-120

-90

-60

-30

0

30

60

90

120

Cu

mu

lativ

e ($

Millio

ns

)

Capital+Chem NCF Cumulative NCF

Phases 1&2: Expenditure & Net Cash Flow

Field pricing based on Edmonton $85/bbl Flat Pricing

BTax ROR vs. Price

0

5

10

15

20

25

30

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

Edmonton Light ($/bbl)

RO

R (

%)

Little Bow ASP Phases I & 2

Phases 1&2 Price Sensitivity: Before Tax ROR

Ba

se P

rice

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

• For ROR = 10%: Field realization = 68 – 17 = 51 $/bbl

Phases 1&2 Recovery Sensitivity: Before Tax RORUpside Cases

BTax ROR vs. Oil Recovery

10

12

14

16

18

20

22

8 9 10 11 12 13 14 15 16

Recovery (% DPIIP)

RO

R (

%)

Little Bow ASP Phases I & 2

Ba

se R

.F.

Increment from Edmonton

price increase to $95/bbl

Increment from EOR

Royalty reform

• Incremental Before Tax PV10 from:

‒ Base price increase is $15MM

‒ EOR royalty could be $20MM

Field pricing based on Edmonton $85/bbl Flat Pricing

ASP Followup Development

Phases 1 & 2

8100LB “P” Pool

Followup

781C8C / X8X

1968U&W Unit

70Total

5100MM Unit

31100LB “I” Pool

W.I. DPIIP*

(mmbbl)ZAR

W.I. (%)

* ERCB DPIIP Data

Zargon LandZargon WellsZargon LandZargon WellsZargon LandZargon WellsZargon LandZargon Wells

ASP Phase 1 & 2

“MM” Unit

“U&W” Unit

“C8C/X8X” Pool

15-018W415-019W4

14-018W414-019W4

Zargon LandZargon WellsZargon LandZargon WellsZargon LandZargon WellsZargon LandZargon Wells

ASP Phase 1 & 2

“MM” Unit

“U&W” Unit

“C8C/X8X” Pool

15-018W415-019W4

14-018W414-019W4

Little Bow Phases 1 - 4 Injection Schedule




Phase 4 ASP Polymer

2021 2022 20232017 2018 2019 20202013 2014 2015 2016

Project Economics - Phases 1 - 4

ASP Development Forecast - Phase 1-4

0

500

1000

1500

2000

2500

2012 2014 2016 2018 2020 2022 2024 2026 2028 2030

BO

PD

Base Phase 1 Phase 2 Phase 3 Phase 4

Zargon W.I. Production

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 4.9

Pipelines 2.4 1.7 4.1

Subsurface 3.2 3.4 6.610.5 5.1 15.6

ASP Chemical 19.7 20.5 40.2

Total 30.2 25.6 55.8

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

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

WWW.ZARGON.CA

Corporate Presentation

Q3 2012 Results

November 7, 2012

zargon - q3 release - november 6 (rev 3a)zargon.ca/wp-content/uploads/2012/02/zargon-q3... ·...

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