Manitok Corporate Presentation December 2013 · 09/12/2013 · Forward-looking Statements Certain statements contained in this presentation may constitute forward-looking information

Manitok Corporate Presentation

December 2013

Forward-looking Statements

Certain statements contained in this presentation may constitute forward-looking information and statements. All statements in this presentation, other than statements of

historical fact, that address events or developments concerning Manitok Exploration Inc. ("Manitok") that Manitok expects to occur are "forward-looking information and

statements". Forward-looking information and statements are often, but not always, identified by the use of words such as "seek", "anticipate", "plan", "continue", "estimate",

"expect", "may", "will", "project", "predict", "propose", "potential", "targeting", "intend", "could", "might", "should", "believe", "budgeted", "scheduled“ and "forecasts", and

similar expressions and variations (including negative variations). In particular, but without limiting the foregoing, this presentation contains forward-looking information and

statements pertaining to the following: future oil, NGLs and gas production and cash flows; additions of future oil and gas reserves and future recovery factors; future drilling

plans, locations and inventory and future seismic activity; predictability, stability and reliability of future oil and gas production; future exploration and development

opportunities; future netbacks and capital expenditures; mergers and acquisitions; future debt reduction; the volumes and estimated value of Manitok's oil and gas reserves;

future results from operations and operating metrics; and future costs and expenses. Forward-looking information and statements are necessarily based on estimates and

assumptions that are inherently subject to known and unknown risks, uncertainties and other factors that may cause Manitok's actual results, level of activity, performance or

achievements to be materially different from those expressed or implied by such forward-looking information and statements. In preparing this presentation, estimates and

assumptions have been made relating to, among other things: prevailing commodity prices and exchange rates; applicable royalty rates and tax laws; future well production

rates; the performance of existing wells; the success of drilling new wells; the availability of capital to undertake planned activities; and the availability and cost of labour and

services. Many of these estimates and assumptions are based on factors and events that are not within the control of Manitok and there is no assurance they will prove to be

correct. Risk factors that could cause actual results to differ materially from those anticipated in these forward-looking information and statements include: the volatility of

natural gas and oil prices; the limitations that Manitok's level of indebtedness may have on Manitok's financial flexibility; declines in the values of Manitok's natural gas and oil

properties resulting in ceiling test write-downs; the availability of capital on an economic basis, including through planned asset monetization transactions, to fund reserve

replacement costs; Manitok's ability to replace reserves and sustain production; uncertainties inherent in estimating quantities of natural gas and oil reserves and projecting

future rates of production and the amount and timing of development expenditures; exploration and development drilling that does not result in commercially productive

reserves; expiration of natural gas and oil leases that are not held by production; hedging activities resulting in lower prices realized on natural gas and oil sales and the need

to secure hedging liabilities; uncertainties in evaluating natural gas and oil reserves of acquired properties and potential liabilities; the negative impact lower natural gas and

oil prices could have on Manitok's ability to borrow; drilling and operating risks, including potential environmental liabilities; transportation capacity constraints and

interruptions that could adversely affect Manitok's cash flow; potential increased operating costs resulting from legislative and regulatory changes such as those proposed

with respect to commodity derivatives trading, natural gas and oil tax incentives and deductions, hydraulic fracturing and climate change; and losses possible from pending or

future litigation.

Manitok's production forecasts are dependent upon many assumptions, including estimates of production decline rates from existing wells and the outcome of future drilling

activity. Although Manitok believe the expectations and forecasts reflected in these and other forward-looking information and statements are reasonable, Manitok can give no

assurance they will prove to have been correct. Such expectations and forecasts can be affected by inaccurate assumptions or by known or unknown risks and uncertainties.

New factors emerge from time to time and it is not possible for management to predict all such factors and to assess in advance the impact of such factor on Manitok's

business or the extent to which any factor, or combination of factors, may cause actual results that differ from those contained in any forward-looking information or

statements.

All of the forward-looking information and statements contained in this presentation are qualified by these cautionary statements. The reader of this presentation is cautioned

not to place undue reliance on any forward-looking information and statements. Manitok expressly disclaims any intention or obligation to update or revise any forward-

looking information and statements, whether as a result of new information, events or otherwise, except in accordance with applicable securities laws.

Reader Advisory

2

Reader Advisory

Reader Advisory

Forward-looking Statements Continued

Accredited Investor

This is not an offer to sell or a solicitation of an offer to purchase securities by Manitok. In Canada, this presentation and its contents are directed only at "accredited

investors" (as defined in National Instrument 45-106 Prospectus and Registration Exemptions). In the United States, any such offer or solicitation will only be made to

"qualified institutional buyers" (as defined in Rule 144A of the United States Securities Act of 1933, as amended ("U.S. Securities Act")) or to "accredited investors" (as

defined in Rule 501(a) of Regulation D under the Securities Act of 1933). By agreeing to receive this presentation, you represent and warrant that you are a person who falls

within one of the foregoing descriptions of persons entitled to receive this presentation and that you agree to be bound by the provisions of this disclaimer. Any subsequent

offer to sell or solicitation of an offer to purchase securities by Manitok will be made by means of offering documents (e.g., term sheet, prospectus, offering memorandum,

subscription agreement and or similar documents (collectively, the "Offering Documents")) prepared by Manitok for use in connection with such subsequent offer or

solicitation and only in jurisdictions where permitted by law. In the event of a subsequent offer to sell or solicitation of an offer to purchase securities by Manitok, investors

should refer to the Offering Documents for more complete information, including investment risks, management fees and fund expenses.

Non-Solicitation

The attached material is provided for informational purposes only as of the date hereof, is not complete, and may not contain certain material information about Manitok,

including important disclosures and risk factors associated with an investment in Manitok. This information does not take into account the particular investment objectives

or financial circumstances of any specific person who may receive it. In the event of a subsequent offer to sell or a solicitation of an offer to purchase securities by Manitok,

more complete disclosures and the terms and conditions relating to a particular investment will be contained in the Offering Documents prepared for such offer or

solicitation. Before making any investment, prospective investors should thoroughly and carefully review the Offering Documents with their financial, legal and tax advisors

to determine whether an investment is suitable for them.

Neither Manitok nor any of its directors, officers, employees, agents or advisors makes any representation or warranty in respect of the contents of this presentation or

otherwise in relation to Manitok or its business. In particular, no representation or warranty, express or implied, is made as to the fairness, accuracy or completeness of the

information or opinions contained herein, which have not been independently verified. No person shall have any right of action (except in case of fraud) against Manitok or

any other person in relation to the accuracy or completeness of the information contained in this presentation. The information contained in this presentation is provided as

at the date hereof and is subject to amendment, revision and updating in any way without notice or liability to any party.

This document and its contents are confidential. It is being supplied to you solely for your information and may not be reproduced or forwarded to any other person or

published (in whole or in part) for any purpose.

Certain information contained herein has been prepared by third-party sources. Such information has not been independently audited or verified by Manitok. Manitok has

used its best efforts to ensure the accuracy and completeness of the information presented.

BOE Conversions The term barrels of oil equivalent ("boe"), as used in this presentation, may be misleading, particularly if used in isolation. Per boe amounts have been calculated using a

conversion ratio of six thousand cubic feet of natural gas to one barrel of oil. This boe conversion ratio of 6:1 is based on an energy equivalency conversion method

primarily applicable at the burner tip and does not represent a value equivalency at the wellhead.

3

* Calculation uses proven plus probable reserves at Dec. 31/12 and average 2012 4th quarter production of 3,078 boe/d.

The Company

4

Market Capitalization at $2.15/share

Common Shares Outstanding, post financing

Options (wgt avg exercise price of $1.96/share)

Insider Ownership, Undiluted / Diluted

Total Net Debt at Sept. 30/13 ($105MM Credit Facility)

~ $162 million

75,530,640

5,484,440

5.9% / 9.4%

$21.4 million

Production ~5,100 boe/d (55% Oil)

Proved plus Probable Reserves Dec 31/12

Reserve Life Index (proved plus probable)*

14,862.3 Mboe (38% Oil)

13.2 yrs

Gross Total Land (78% Avg Working Interest)

Gross Undeveloped Land (84% Avg Working Interest)

93% of net land position is undeveloped

380,000 acres

327,900 acres

Corporate Snapshot – MEI on TSX-V

The People

Bruno Geremia, C.A. - Chairman

VP Finance & CFO, Birchcliff Energy (BIR – TSE)

Robert J. Dales

Director of Arcan Resources (ARN–TSX)

Massimo Geremia

President & CEO, Manitok Energy (MEI – TSX)

Wilfred A. Gobert

Retired, former Vice Chairman of Peters & Co; Director of Canadian Natural Resources (CNQ –

TSE) and Trilogy Energy Corp. (TET – TSE)

Greg Peterson

Partner, Gowlings Canada

Tom Spoletini

Independent Businessman; founder of several successful private companies

Cameron Vouri, P.Eng.

COO, Manitok Energy (MEI – TSX); previously President of Provident Energy Trust’s Canadian

business unit.

5

Board of Directors

Massimo Geremia, President & CEO

21 years of public company experience in Oil &Gas, Real Estate and Finance; previously with Birchcliff Energy Ltd.,

Equatorial Energy Inc. & Boardwalk Equities Inc.;

Cameron Vouri, P. Eng, COO

Former President Upstream Canadian Oil and Gas Business unit at Provident Energy Trust; instrumental in the

growth of Provident from 3,000 boe/d to 30,000 boe/d;

Southern Alberta experience at both Provident and Koch of over 3,000 boe/d;

Robert Dion CA, VP Finance & CFO

20 years of industry experience in senior financial positions at Compton Petroleum Corp., Canadian Natural

Resources Ltd., Rio Alto Exploration Ltd. and Nexen Inc.

Don Martin, B.Sc. Honours, VP Exploration, Plains

33 years of progressive geoscience experience; previously with Evergreen Resources, Marathon Canada, Anderson

Exploration and Pan Canadian Petroleum;

Yvonne McLeod, P.Eng, VP Drilling and Facilities

18 years of industry experience; previously with Talisman Energy and Imperial Oil;

Greg Feltham, M.Sc., Senior Manager Exploration, Foothills 12 years of industry experience; previously with Talisman Energy;

Robert Brown M. Sc., Senior Manager Business Development 17 years of industry experience; previously with Talisman Energy, Vermillion Resources Ltd. and Dorset Exploration;

6

Experienced Management Team

Exceptional Growth to Continue

2012

Actual

2013 Guidance

Est.

Annual

Growth 2014 Guidance

Est.

Annual

Growth

2013 Production

Annual (boe/d) 2,389 4,000 – 4,100 70% 6,000 – 6,200 50%

% Oil and liquids 40% 52% 30% 62% - 65% 21%

Exit rate (boe/d) 3,860 5,300 – 5,500 40% 7,100 – 7500 35%

% Oil and liquids 54% 54% – 56% 2% 67% – 70% 25%

Annual Production per Share (boe) .0124 .0214 72% .0294 37%

2013 Benchmark pricing

Crude oil – WTI (US$) 97.69 90.00

$CAD/$US exchange rate 1.03 1.035

Crude oil – WTI ($CAD) 100.62 93.15

Differential – WTI ($CAD) to Realized (8.44) (10.00)

Natural gas – AECO daily spot ($/mmbtu) 3.13 3.30

Netbacks

2013 Operating netback ($/boe) 27.62 31.50 14% 35.90 14%

2013 Funds from operations netback ($/boe) 21.82 27.34 25% 31.80 16%

2013 Funds from operations 19 million 40 – 42 million 115% 68 – 72 million 70%

Capital expenditures, net 37 million 81 – 83 million 121% 100 – 102 million 23%

Net debt at year end 10 million 32 – 34 million 230% 60 – 64 million 88%

7

23 24 R25

Twp 28

27

26

25

24

23

22

A Significant Opportunity at Entice

Underexploited - Only

250 well penetrations

in the Mannville or

deeper on the lands. Over 200 MMbbls of

cumulative oil production and

12 Tcf of cumulative gas

production in the surrounding

area.

Past drilling activity has

been predominantly east of

MEI’s block due to

PanCanadian’s successful

development of oil pools

near Brooks and Bassano.

Activity moved west toward

the block over time, but

merger with AEC to form

Encana altered focus to

finding large gas reserves

and property has been on

the back burner since then.

8

Second Core Area Reduces Risk Profile and Increases Exposure to Oil

Targeting a higher oil weighting, a production level above 10,000 boe/d and predictable long term

growth through a large transparent drilling inventory in order to improve market valuation;

Estimated dry hole costs of $650,000 to $1.5 million per well and all-in well costs of ~$1- $3 million at

Entice balance Manitok’s risk/reward proposition relative to Foothills’ capital costs;

Balancing Corporate Risk/Reward

Significant Oil in Place and Under Exploited

Manitok believes that there are potentially risked recoverable oil reserves of ~180 MMbbls based on

primary recovery from Glauconitic, Ellerslie (Basal Quartz), Pekisko, Nisku and other Devonian;

Limited activity on the block in the past with only 250 well penetrations into the Mannville or deeper;

drill density in surrounding lands much higher;

Over 55 log leads on potential oil pools from the 250 wells; pools could each have between 500 Mbbls

to >8 MMbbls of recoverable oil.

Large Contiguous Land Base to Develop Efficient, Scalable Operations

Footprint spanning nearly 9 townships (~96,800 net acres) with PNG rights from the base of the Belly

River to the base of the Devonian on even sections (checker board);

3 year primary term plus an option to extend for an additional 3 years under the same terms;

$16.5 million bonus and a $106 million capital commitment over 3 years;

Ability to joint venture or farm out opportunities on the land block to other parties;

2 provisions in agreement to capture odd sections; one through leasing adjacent lands or equalizing

when a new pool has been proven and one through a right of first offer;

100% working interest with freehold royalties on production with a minimum of 10% and maximum of

30% on a sliding scale based on both volume and price; no other GORs or working interest giveaways;

9

Access to Proprietary Seismic Data and Public Data on ~250 Wellbores

Leased lands include full 3D seismic coverage (~420 sq. miles);

Reduced exploration and development risk;

Replacement value of 3D seismic greater than $40 million;

Multi-zone Potential

Drill stem tests on various old wellbores confirm the existence of oil across multiple zones;

Large set of stacked pay opportunities provides risk mitigating bail-out zones

Significant offsetting drill results and production in a variety of zones; Manitok’s primary targets

include the Glauconitic, Ellerslie (Basal Quartz), and Nisku zones; Pekisko, Upper Mannville and

deeper Devonian zones are secondary targets;

Access to Infrastructure

Oil development will be via single and larger multiple well batteries;

Priority 2 processing status in Encana facilities; royalty stream motivates Encana to ensure

associated gas volumes from Manitok’s oil production are on stream;

Two Encana gas plants on the lands with current estimated spare capacity of 15MMcf/d;

A major oil shipping pipeline is only 20 km East of the Block, and three truck terminals exist at

Hussar, West Drumheller, and Rowley along that pipeline;

Major gas transportation pipelines run through land block;

Factors Mitigating Drilling &

Production Risk

10

23 24 R 25

28

27

26

25

24

23

Twp 22

Glauconitic

Ellerslie / BQ

Pekisko

Nisku

Wabamun

Viking

New Pool Log Leads – 55 have been identified.

Glcc ‘F’ Pool

Cum 6 MMBO

20 Wells, 1987

Swallwell Nisku Pools

Cum 5 MMBO

17 wells, 1969 Nsku Wayne ‘A’ Pool

Cum 11 MMBO

40 Wells, 1993

Glcc ‘A-C’ Pool

Cum 3.7Bcf &

370 MBO

4 Wells, 1979

Glcc Hussar‘A’ Pool

Cum 26 MMBO

46 Wells, 1958

Glcc ‘A’ Pool

Cum 1.2 MMBO

9 Wells, 1992

Elrl Entice ‘B’ Pool

Cum 5 MMBO

39 Wells, 1987

Glcc Blackfoot ‘D’ Pool

Cum 7 Bcf & 741 MBO

9 Wells, 1995

Wbmn ‘Swalwell

D-1 A’ Pool

Cum 4 MMBO

59 Wells, 1996

Wayne-Rosedale Ellerslie

Large OOIP of 5-20 MMBO/section

Recent Cenovus Hz drilling activity

55 new pool log leads

identified.

Each new pool could have

recoverable oil of 500 MBO

to >8 MMBO.

New pool discoveries will

lead to an increased drilling

inventory over time.

New Pool Leads & Offset Production

11

Large Oil in Place Over Multiple

Zones in the Mannville and Devonian

Large oil in place across multiple zones combined with attractive economics to support strong growth rates

1) Estimates for target zone oil in place and recovery factors as per GeoScout and the Alberta ERCB

2) Illustrative economics based on GeoScout data, industry reports, company presentations, and as per Manitok management

Entice Region - Estimated Oil in Place / Recoverable Oil & Illustrative Well Economics

Viking Glauconite Ellerslie /

Basal Quartz Pekisko Nisku Total

Entice Opportunity - Estimated Oil in Place / Recoverable Oil (1)

Median Oil per Section Mbbl 2,549 5,060 4,758 4,756 3,556 -

Number of Pools Analyzed # 43 426 354 114 4 -

Original Oil in Place Mbbl 412,938 819,686 770,718 770,473 576,004 3,349,819

Estimated Recovery Factor % 9% 14% 8% 9% 15%

Estimated Recoverable Oil Mbbl 38,313 114,078 63,785 67,307 86,170 369,652

Risk Factor 50%

Estimated Risked Recoverable Oil 184,826

Illustrative Well Economics (2)

Well Cost $mm $1.2 (v) $1.6 (v) $1.6 (v) $2.7 (hz) $1.9 (v)

EUR mboe 60 115 115 135 315

IP30 Rate boe/d 65 110 110 105 117

% Oil % 70% 82% 82% 90% 87%

1st Year Average boe/d 40 70 70 75 98

Edmonton Par C$/bbl $95.00 $95.00 $95.00 $95.00 $95.00

AECO C$/mcf $3.50 $3.50 $3.50 $3.50 $3.50

F&D $/boe $20.09 $13.91 $13.91 $20.03 $6.03

Capital Efficiency $/boe/d $29,900 $22,857 $22,857 $36,201 $19,388

Netback $/boe $50.79 $50.35 $50.35 $56.98 $55.84

Recycle Ratio x 2.5x 3.6x 3.6x 2.8x 9.2x

NPV $mm $0.7 $3.0 $3.0 $2.2 $9.0

IRR % 28% 82% 82% 32% 150%

18 MMbbls, only

10% of ERRO,

would quadruple

Manitok’s current

2P oil reserves.

12

Potential Recoverable Barrels

10-31-028-24W4

Nisku - Devonian

5.8 OOIP (mmbbls)

06-16-028-24W4

Ellerslie - Cretaceous

22.3 OOIP (mmbbls)

06-34-027-24W4

Pekisko - Mississippian

0.818 OOIP (mmbbls)

14-08-027-23W4

Basal Quartz - Cretaceous

6.8 OOIP (mmbbls)

06-15-027-23W4

Upper Glauconitic - Cretaceous

7.2 OOIP (mmbbls)

11-23-027-23W4

Basal Quartz - Cretaceous

3.12 OOIP (mmbbls)

06-34-027-23W4

Glauconitic - Cretaceous

7.6 OOIP (mmbbls)

09-06-028-23W4


07-10-028-23W4


4.5 OOIP (mmbbls)

04-01-029-24W4

Nisku - Devonian

6.6 OOIP (mmbbls)

06-31-027-24W4

Upper Viking - Cretaceous

06-26-027-24W4


6.8 OOIP (mmbbls)

13-33-026-26W4

3.6 OOIP (mmbbls)

14-08-027-24W4

Viking and Basal Quartz - Cretaceous

07-11-027-24W4

Viking - Cretaceous

11.2 OOIP (mmbbls)

16-11-026-26W4

9.0 OOIP (mmbbls)

06-16-026-24W4


5.6 OOIP (mmbbls)

13-21-025-24W4

Glauconitic & Ellerslie - Cretaceous

48.5 OOIP (mmbbls)

14-32-027-23W4


10-20-022-25W4


17.0 OOIP (mmbbls)

08-20-022-25W4


17.0 OOIP (mmbbls)

06-33-022-25W4


04-02-023-25W4


6.8 OOIP (mmbbls)

Estimated OOIP # of Pools

Average

(mbbls)

Median

(mbbls)

25th

Percentile

(mbbls)

75th

Percentile

(mbbls) Min Max

Estimated

Recovery Factor

Glauconitic 426 6,374 5,060 3,161 8,030 528 52,961 9%

Ellerslie/Basal Quartz 354 6,279 4,758 3,143 7,911 721 60,009 8%

Viking 43 3,358 2,549 1,571 4,397 989 11,277 11%

Pekisko 114 5,729 4,756 2,858 7,411 827 25,776 9%

Wabamaun 4 4,034 3,556 2,850 4,739 2,398 6,625 11%

Bakken na na na na na na na na

13

Many Ellerslie (Basal Quartz)

Prospects with Significant OOIP • 14 bypassed pay opportunities identified to date, ;

• Internal estimates of 5 - 20 MMbbls of OOIP per

section with primary recovery factors of 4 - 5% with

vertical wells and 8 - 15% with horizontal wells;

• Modelled pool exhibits the following reservoir

characteristics:

- porosity of 12 - 18%

- permeability of 10 - 250 md

- Water saturations of 30 - 45%

- Oil gravity of 28º - 35º API

• Vertical Single well economic parameters:

- D/C/T $1.65 million

- IP(30d) 95 boe/d

- EUR 120 Mboe

- NPV10 $2.3 million

- IRR 52%

• Horizontal Single well economic parameters:


- IP(30d) 250 boe/d

- EUR 220 Mboe


- IRR 57%

T26

T2

5

T23

T22

Ellerslie (BQ) Entice ‘B’ Pool

Produced 5 MMBO

39 Wells (only 1 Hz well)

1987

Lower Mannville produced ~15 MMbbls

since 1979. Drilling of ELRL (BQ) Hz

wells since 2012 raised oil production

from ~1,000 bbls/d to a peak of ~4,000

bbls/d; currently ~3,000 bbls/d

Ellerslie (BQ) Wells are RED

14

Attractive Nisku Prospect

• Swallwell Nisku D-2 A Pool discovered in 1969;

• 4-1-29-24W4 (green dot on map) is in a separate pool

from the main pool and has produced 29,000 BO;

• Seismic interpretation indicates 4-1 is located on the

edge of a pool extending south into section 36-28-24W4;

• Reservoir parameters of 8% porosity, 200 to 500md

permeability, 25% Sw, oil gravity of 37 API; OOIP

estimated at 5.5 MMBO per section;

• Single well economic parameters:


- IP(30d) 117 boe/d

- EUR 315 Mboe

- NPV10 $9 million

- IRR >100%

15

Produced

5 MMBO;

14.9 MMBO

of OOIP

4-1-29-24W4

Many Glauconitic Channel Prospects

• 11 bypassed log leads initially identified ; channel

prospects currently being validated by 3D seismic

interpretation and reservoir rock analysis;

• Analogous production at Rockyford (OOIP 19

MMBO, production of 6.2 MMBO);

• Excellent reservoir with 20% porosity, 200 to 500md

permeability, 25% Sw, oil gravity of 28-35 API;

• Single well economic parameters:


- IP(30d) 105 boe/d

- EUR 115 Mboe


- IRR 80%

Rockyford U Mann F Pool

Produced 6 MMbbls

20 wells since 1987

Seismic Interpretation of Glauc Channel Trends in T28-25W4

Glauconitic Wells are GREEN

Glcc ‘A’ Pool

Produced 1.2 MMbbls

9 Wells since 1992

16

Many identified log leads resemble Edge Well similar to the

12-22 well ( 1 on the cross section)

Entice Glauconitic Analog

• Rockyford U Mann F Pool located just east of our

acreage has OOIP of 19MMBO with a primary plus

enhanced recovery factor of 32%;

• F pool has produced a total of 6.2 MMBO since

going on production in 1981 from a total area of

1,043 acres (1.6 sections); channel deposit is

approximately 400m wide;

Cross Section Illustrating Thickening of Reservoir From the

Edge Well to the Centre of the Rockyford Pool

Thin Channel Lag at Edge

Thick Channel Sand in Centre

Majority of Identified Bypass Pay Wells are Thin Channel Lag Deposits (Edge Wells)

12-22 14-22

Well 2 Well 1

1

2

17

Total Cardium Hz Cost (DC, C & E) $5.2 MM

30 Day IP Rate (risked at 70%) 320 Boe/d

Reserves (risked at 70%) 411 Mboe

BT NPV10 (risked at 70%) $13.4 MM

BT IRR* (risked at 70%) 94%

Recycle Ratio / Payout 3.2x / 1.3 yr

Planned 2013 Drills 11 (~6.5 net)

Structural

Cross-section

Stolberg Focus

First 3 (2.4 net) Stolberg section 29 wells have

cumulatively produced ~679,000 bbls (536,000 net) of light

oil in 16 months; total produced gross oil from the Stolberg

pool since 2012 is ~1.1 MMbbls;

Discovery of new Cardium oil sheet at Stolberg will add

significant reserves and production;

OOIP of up to 20 million bbls per section over 6 sections;

~20 additional drilling locations along Stolberg trend in

order to optimize primary recovery of 10%; could recover

10% to 30% of OIP in time with a secondary recovery

scheme.

18

* The Price deck used to calculate the IRR is in the appendix.

Cardium Oil Production at Stolberg

Main Stolberg structure

Additional untested structures

Cordel structure

Structural cross section through T42-15W5 showing both the Cordel and Stolberg Cardium pools along

with several untested structures.

>1,000 Meter Hydrocarbon Column

at Stolberg

19

1,0

00

m

Large OOIP - Reservoir parameters calibrated to core and

logs suggest ~12.9 MMbbls OOIP per section. Due to the

folded, faulted, and steeply dipping nature of the Stolberg

Cardium structure, it is possible to fit up to 2 - 3 sections of

rock volume in one geographic section (640 acres). This

results in potentially >20 MMbbls OOIP per one

geographic section.

Backlimb - ~80% of production and drilling to date has been

delineating the main backlimb of the Stolberg structure; deepest

well penetrations in the field suggest this main backlimb is up to

1200m in height.

Forelimb - Three well penetrations across the fold have

discovered an oil bearing forelimb that contains similar reservoir

quality and allows for future drilling locations; two of these

forelimb wells have cumulatively produced >110,000 bbls.

Backlimb

Forelimb

20

Stolberg Cardium Oil – Large OOIP

New Sheet / Pool Discovery: 2 wells drilled into new pool (1 on sect 21 & 1 on sect 29) and

tested at rates up to 604 boe/d and 747 boe/d of 44º API oil.

New pool provides additional drilling locations and reserves;

estimates of ~15 to 20 MMbbls OOIP over 2 sections.

Future drilling locations at Stolberg:

~ 6-8 wells into producing backlimb

~ 4-6 wells into new pool discovery

~ 8-12 wells into forelimb

Water flood potential at both Cordel and Stolberg:

AER has approved Cordel water flood plan.

Initial reservoir modelling suggests it may be possible to double

recovery factor in the field from ~9% to as much as ~20%.

Will provide information for an eventual water flood of the

Stolberg pool.

New Pool

Discovery

Total Cardium Well Cost (DC, C & E) $4.7 MM





Recycle Ratio / Payout 3.0x / 1.4 yrs

Potential 2013 Drills 2 (1.4 net)

1st Cardium farmin well tested at ~200 bbls/d of

light oil; potentially 6 MMbbls OOIP per section

and >15 drilling locations if Manitok is right;

Earned 70% of 7 sections (3,136 net acres) with

first drill; Manitok has the option to drill 2

additional wells at 100% of the cost to earn a 70%

interest in the remaining 12.6 sections (5,645 net

acres);

Second farmin well drilling; will produce both wells

for 2 to 4 months before deciding to drill 3rd well.

21 * The Price deck used to calculate the IRR is in the appendix.

A Great Start at Quirk Creek

MEI 11-31-20-3W5

Hz target depth = -785m SS

Producing sheet climbs to at least

123m ASL as seen in 100/16-20-20-

3W5 proving up a hydrocarbon column

> 900m in height

Cardium B

Quirk Creek Cardium Oil

22

23

Closing Summary

Manitok will continue to focus on growth in the

foothills by using its technical knowledge and

experience in the area at a time when there is little

competition;

Addition of the large land position in the Entice

area provides potential for scale, increased oil

production and greater visibility of drilling

inventory over time;

Long term corporate plan to become a dominant

exploitation / exploration group in both the

Foothills and SE Alberta over the next 5 to 10

years;

24

Appendix

25

Hedging

As at June 30, 2013, the Corporation held the following derivative financial instruments:

Subject of

Contract

Notional

Quantity

Remaining Term

Reference

Average

Strike Price

Contract

Traded

Oil 300 bbls/d July 1, 2013 to December 31, 2013 CAD$ WTI $97.65 Swap


Oil 500 bbls/d July 1, 2013 to December 31, 2013 CAD$ WTI $98.00 Swap(1)





Oil 500 bbls/d January 1, 2014 to December 31, 2014 CAD$ WTI $96.00 Swap

Oil 500 bbls/d July 1, 2013 to December 31, 2013 CAD$ EDM-WTI Diff $6.80 Swap

Natural gas 5,000 GJs/d July 1, 2013 to December 31, 2013 CAD$ AECO $3.40 Put(2)

Natural gas 5,000 GJs/d July 1, 2013 to December 31, 2013 CAD$ AECO $3.40 Put(3)

Oil 500 bbls/d January 1, 2014 to December 31, 2014 CAD$ WTI $97.65 Swaption(4)






Subsequent to June 30, 2013, the Corporation entered into the following derivative financial instruments: Subject of

Contract

Volume

Term

Reference

Strike Price Contract Traded



(1) In July 2013, the contract was terminated effective July 1, 2013 and the payment related to the termination has been included in the calculation of the fixed price of the transaction disclosed in the table below regarding derivative financial instruments entered subsequent

to June 30, 2013.

(2) The counter-party to this contract receives a deferred put option premium of $0.35/Gigajoule.

(3) The counter-party to this contract receives a deferred put option premium of $0.39/Gigajoule.

(4) The counter-party to this contract holds a one-time option no later than December 31, 2013 to extend a swap on 500 barrels per day of oil at CAD$97.65 for the period indicated. The fair value amount represents the cost the Corporation would incur to exit the contract.



(7) In August 2013, the contract was terminated effective January 1, 2014 and the payment related to the termination has been included in the calculation of the fixed price of the transaction disclosed in the table below regarding derivative financial instruments entered

subsequent to June 30, 2013.



Price Deck

SPROULE - MARCH 31, 2013

26

- Prices in Canadian Dollars -

Year

1

WTI

Cushing

Oklahoma

$US/Bbl

Edmonton

Par Price

40 API

$/Bbl

Synthetic

Crude Oil

Edmonton 34

API

$/Bbl

Cromer

LSB

35 API

$/Bbl

Hardisty

Lloydblend

20.5 API

$/Bbl

Western Canada

Select (WCS)

20.5 API

$/Bbl

Cromer

Medium

29.3 API

$/Bbl

2

Energy Cost

Inflation

Rate

%/Yr

Cost

Inflation

Rate

%/Yr

Exchange

Rate

$US/$Cdn

2013 9 Mo Est 92.85 87.92 94.42 85.92 71.21 71.21 80.01 16.9% 1.5 0.999

2014 90.51 85.58 92.08 83.58 70.17 70.17 78.73 -3.3% 1.5 0.999

2015 87.69 87.75 94.25 85.75 72.84 72.84 80.73 -3.1% 1.5 0.999

2016 93.22 93.30 99.80 91.30 77.44 77.44 85.83 6.3% 1.5 0.999

2017 96.96 97.03 103.53 95.03 81.51 81.51 90.24 4.0% 1.5 0.999

2018 98.41 98.49 104.99 96.49 82.73 82.73 91.59 1.5% 1.5 0.999

2019 99.89 99.96 106.46 97.96 83.97 83.97 92.97 1.5% 1.5 0.999

2020 101.38 101.46 107.96 99.46 85.23 85.23 94.36 1.5% 1.5 0.999

2021 102.91 102.99 109.49 100.99 86.51 86.51 95.78 1.5% 1.5 0.999

2022 104.45 104.53 111.03 102.53 87.81 87.81 97.21 1.5% 1.5 0.999

2023 106.02 106.10 112.60 104.10 89.12 89.12 98.67 1.5% 1.5 0.999

2024 107.61 107.69 114.19 105.69 90.46 90.46 100.15 0.02 1.50 1.00

Escalation Rate of 1.5% Thereafter

1. 40 Deg API, 0.4% sulphur

2. Based on WTI

Year

Henry Hub Price

$US/MMbtu

AECO - C

Spot

$/MMbtu

Alliance

Pipeline

$/MMbtu

B.C. Westcoast

Station 2

$/MMbtu

Huntingdon /

Sumas 30 d

Spot $/MMbtu

Dawn

$/MMbtu

Ethane

Plant

Gate

$/Bbl

Edmonton

Propane

$/Bbl

Edmonton

Butane

$/Bbl

Edmonton

Pentanes

Plus

$/Bbl

Plant

Gate

Sulphur

$/LT

2013 9 Mo. Est 3.87 3.52 2.82 3.46 4.01 4.12 9.77 49.09 65.53 106.41 86.28

2014 4.14 3.80 3.20 3.74 4.29 4.40 10.54 48.03 63.78 103.58 87.57

2015 4.30 3.95 3.40 3.89 4.44 4.55 10.96 49.25 65.41 106.21 83.65

2016 5.00 4.66 4.15 4.60 5.15 5.25 12.91 52.65 69.54 112.92 79.60

2017 5.66 5.32 4.86 5.26 5.81 5.91 14.73 55.05 72.32 117.44 80.80

2018 5.74 5.40 4.95 5.34 5.89 6.00 14.96 55.82 73.41 119.20 82.01

2019 5.83 5.49 5.03 5.43 5.98 6.08 15.20 56.61 74.51 120.99 83.24

2020 5.91 5.57 5.12 5.51 6.06 6.17 15.45 57.40 75.63 122.81 84.49

2021 6.00 5.66 5.21 5.60 6.15 6.26 15.69 58.21 76.76 124.65 85.75

2022 6.09 5.75 5.30 5.69 6.24 6.35 15.94 59.03 77.91 126.52 87.04

2023 6.18 5.84 5.39 5.78 6.33 6.44 16.19 59.86 79.08 128.42 88.35

2024 6.28 5.94 5.48 5.88 6.43 6.53 16.45 56.77 80.27 130.34 89.67

Escalation Rate of 1.5% Thereafter

Manitok’s Foothills Area Appendix

27

Potential Value Creation in the Foothills

* Based on Management’s internal assessment which is subject to various risks including, but not limited to, geological, drilling, reservoir

deliverability, access to capital, mineral rights expiration, commodity prices, availability of services and cost inflation.

** Used Sproule March 31, 2013 price forecast. See Appendix for details.

Northern AB

Foothills

Central & Southern

AB Foothills

Oil Gas Oil Gas

Total per Well Capital* (Drill, Case, Complete, Equip &

Tie) ($MM) 5.2 5.6 5.8 6.1

Average Reserves per Well* (Mboe) 291 650 545 854

Development Cost per boe $17.87 $8.62 $10.64 $7.14

IP30 Gas (Mcf/d) 136 2,253 246 4,390

IP30 Oil (bbl/d) 236 25 402 51

Total Production per Well* (boe/d) 259 401 443 783

Operating Expenses per boe $11.19 $5.40 $11.00 $6.85

Royalty Rate 35% 24% 37% 24%

Net Present Value @10%** ($M) 3,189 4,798 8,454 8,184

Payout (years) 1.9 2.0 1.0 1.1

Internal Rate of Return 48% 53% 147% 118%

Total

Net Future Development Locations* 10 15 113 43 181

Total Potential Reserves* (Mbbl or Mboe) 2,750 8,250 41,132 33,683 85,815

Total Capital Required* ($MM) 52.0 84.0 655.4 262.3 1,053.7

Total Potential Net Present Value @10%** ($MM) 31.9 72.0 955.3 351.9 1,411.1

28

100/14-15-44-17W5:

Cum production 247,899 bbls

0.2bcf gas

100/10-29-44-17W5:


0.04bcf gas

100/10-11-44-17W5:


Watered out

Petrus 11-31: oil and water

Petrus 1-15: gas and water

Brown Creek Cardium Oil

Total Cardium Hz Cost (DC, C &

E)

$5.2 MM





Recycle Ratio / Payout 3.2x / 1.3yr

Potential 2014 Drills 2 (1.0 net)

Multiple light oil-bearing sheets

similar to the Cordel and Stolberg

oil pools at 1,500 – 1,800m;

potential for 30 - 40 MMbbls OOIP

Under-exploited with only 3

vertical wells in the oil pool to date;

Leading sheets with significant

liquids rich natural gas potential;

* The Price deck used to calculate the IRR is in the appendix.

29

Avg porosities:

9-12%

Open hole logs over 100/14-15-44-17W5 show a fault repeated Cardium sandstone, the lower

of which has a cumulative production of 247,899 bbls of oil (open hole completion, no frac stimulation)

Cardium A

Cardium A


30

Proposed well

Testing two sheets

100/14-15 producing sheet

247,899 bbls cum to date

Brown Creek Cardium

reservoir broken into a series

of faulted imbricates lending

to isolated pools with high

fracture intensity

Technical team has been

evaluating area to map

individual thrust sheets and

determine which ones have

highest probability of oil

potential.

Drilling in Brown Creek may

commence in 2014.

Potentially 2 to 3 well program

to test undrilled thrust sheets

for oil.


31

ICP (2824)

ST#1 Net sand: 220m

ST#1 Gross sand: 500m

Inc Net sand: 40m

Cabin Creek 10-14-55-03W6

Reservoir accessed as of June 14/2013 (TD)

MD: 3333mMD. Intersected a total of 500m gross sand, 260m net pay

TD Top Card sst (2717mMD)

Top Card sst (3005mMD) Top Card sst (3324mMD)

KOP(2939)

Hydrocarbon column penetrated but with higher water cuts and lower than expected

permeability. Workover operations ongoing on nearby Cardium penetrations to earn

additional interest and confirm future plans for the area. Workover operations will

determine height of oil column above MEI 10-14 well.

Cabin Creek Cardium Oil

32

Manitok’s Entice Area Appendix

33

Top Liquids Wells – Entice Area

Top Liquids Wells by Cumulative Production - Entice Region

-

100,000

200,000

300,000

400,000

500,000

600,000

700,000

800,000

900,000

1,000,000T

AQ

A -

(1

0-1

5-

02

9-2

4W

4)

TA

QA

- (

14

-11

-

02

9-2

4W

4)

TA

QA

- (

08

-15

-

02

9-2

4W

4)

Te

rre

x -

(0

6-1

8-

02

2-2

5W

4)

TA

QA

- (

10

-14

-

02

9-2

4W

4)

TA

QA

- (

13

-12

-

02

9-2

4W

4)

Te

rre

x -

(1

4-0

7-

02

2-2

5W

4)

Te

rre

x -

(1

4-1

8-

02

2-2

5W

4)

Te

rre

x -

(0

4-1

8-

02

2-2

5W

4)

Mik

a -

(1

0-2

0-0

22

-

25

W4

)

En

ca

na

- (

14

-26

-

02

6-2

3W

4)

Te

rre

x -

(0

2-1

9-

02

2-2

5W

4)

Te

rre

x -

(1

0-1

8-

02

2-2

5W

4)

En

ca

na

- (

12

-35

-

02

7-2

3W

4)

Te

rre

x -

(1

0-1

8-

02

2-2

5W

4)

EO

G -

(1

6-0

4-0

29

-

24

W4

)

Te

rre

x -

(0

3-0

7-

02

2-2

5W

4)

Te

rre

x -

(1

2-0

6-

02

2-2

5W

4)

En

ca

na

- (

06

-35

-

02

7-2

3W

4)

Te

rre

x -

(0

2-1

8-

02

2-2

5W

4)

Co

no

co

- (

02

-21

-

02

1-2

6W

4)

To

tal

Cu

mu

lati

ve

Pro

du

cti

on

(b

oe

) Gas

Liquids

34

Top Liquids Wells - CVE Since 2011

Top Liquids Wells by Total Cumulative Production Since 2011 - Entice Region

-

20,000

40,000

60,000

80,000

100,000

120,000

140,000

160,000

10

6/0

7-0

8-0

27

-19

W4

/00

10

3/1

3-1

2-0

17

-11

W4

/00

10

2/1

3-1

5-0

27

-18

W4

/00

10

0/1

6-1

5-0

27

-18

W4

/00

10

0/0

1-1

0-0

27

-18

W4

/00

10

5/0

7-0

8-0

27

-19

W4

/00

10

0/1

2-3

6-0

16

-14

W4

/00

10

0/0

3-2

1-0

16

-14

W4

/00

10

3/0

1-0

2-0

20

-15

W4

/02

10

2/1

3-2

5-0

19

-15

W4

/02

10

0/0

7-3

6-0

19

-15

W4

/02

10

3/1

6-1

1-0

17

-14

W4

/00

10

2/0

2-1

7-0

16

-15

W4

/00

10

4/1

1-1

0-0

17

-11

W4

/00

10

0/1

0-1

0-0

26

-17

W4

/00

10

0/0

9-1

0-0

20

-14

W4

/02

10

3/0

7-0

4-0

19

-16

W4

/02

10

4/1

6-2

6-0

19

-15

W4

/02

10

0/0

3-0

7-0

24

-17

W4

/00

10

3/1

0-0

7-0

18

-15

W4

/00

10

2/0

3-2

9-0

25

-20

W4

/00

10

2/0

5-1

1-0

22

-16

W4

/00

10

3/0

5-0

1-0

20

-15

W4

/00

10

0/0

2-1

0-0

27

-18

W4

/00

10

3/0

3-3

6-0

19

-15

W4

/00

To

tal

Cu

mu

lati

ve

Pro

du

cti

on

(b

oe

)

Gas

Liquids

35

Top Liquids Wells – Cenovus Since

2011

Operator UWI

Date Well

Licensed

On Production

Date

Last Date On

Production

Producing/Targeted

Formation

Cumulative Production

(bbl) % Liquids Well Status TVD

Cenovus Enrg Inc 106/07-08-027-19W4/00 Aug 2011 Dec 2011 Aug 2013 Kellrslie 146,799 82% Pumping OIL 1,399

Cenovus Enrg Inc 103/13-12-017-11W4/00 Sep 2011 Dec 2011 Aug 2013 Kglauc_ss 139,671 80% Flowing OIL 942

Cenovus Enrg Inc 102/13-15-027-18W4/00 Jul 2011 Dec 2011 Aug 2013 Kellrslie 126,125 85% Pumping OIL 1,286

Cenovus Enrg Inc 100/16-15-027-18W4/00 Jul 2011 Nov 2011 Aug 2013 Kbs_qtz 121,657 80% Pumping OIL 1,288

Cenovus Enrg Inc 100/01-10-027-18W4/00 Jun 2012 Dec 2012 Aug 2013 Kellrslie 114,156 82% Flowing OIL 1,289

Cenovus Enrg Inc 105/07-08-027-19W4/00 Aug 2011 Nov 2011 Aug 2013 Kellrslie 111,103 84% Pumping OIL 1,399

Cenovus Enrg Inc 100/12-36-016-14W4/00 Sep 2012 Dec 2012 Aug 2013 Kmannvl 99,769 84% Flowing OIL 959

Cenovus Enrg Inc 100/03-21-016-14W4/00 Dec 2012 Mar 2013 Aug 2013 Kglauc_ss 97,935 65% Flowing OIL 991

Cenovus Enrg Inc 103/01-02-020-15W4/02 Dec 2011 Mar 2012 Aug 2013 Kglauc_ss 95,809 78% Pumping OIL 1,013

Cenovus Enrg Inc 102/13-25-019-15W4/02 Dec 2010 Feb 2011 Aug 2013 Kglauc_ss 92,692 76% Pumping OIL 1,009

Cenovus Enrg Inc 100/07-36-019-15W4/02 Oct 2011 Nov 2011 Aug 2013 Mpekisko 91,154 73% Flowing OIL 1,009

Cenovus Enrg Inc 103/16-11-017-14W4/00 Sep 2012 Dec 2012 Aug 2013 Kglauc_ss 89,340 87% Pumping OIL 958

Cenovus Enrg Inc 102/02-17-016-15W4/00 Jul 2012 Aug 2012 Aug 2013 Mpekisko 87,257 76% Pumping OIL 1,015

Cenovus Enrg Inc 104/11-10-017-11W4/00 Oct 2012 Dec 2012 Aug 2013 Kglauc_ss 84,680 72% Flowing OIL 935

Cenovus Enrg Inc 100/10-10-026-17W4/00 Jan 2012 Sep 2012 Aug 2013 Kellrslie 75,787 34% Pumping OIL 1,252

Cenovus Enrg Inc 100/09-10-020-14W4/02 May 2012 Jul 2012 Aug 2013 Mpekisko 75,414 78% Flowing OIL 1,017

Cenovus Enrg Inc 103/07-04-019-16W4/02 Oct 2010 Jan 2011 Aug 2013 Kglauc_ss 71,391 92% Pumping OIL 1,066

Cenovus Enrg Inc 104/16-26-019-15W4/02 Oct 2011 Dec 2011 Aug 2013 Kglauc_ss 68,870 71% Flowing OIL 1,009

Cenovus Enrg Inc 100/03-07-024-17W4/00 Feb 2011 Apr 2012 Aug 2013 Kellrslie 68,588 23% Pumping OIL 1,242

Cenovus Enrg Inc 103/10-07-018-15W4/00 Oct 2010 Feb 2011 Aug 2013 Kglauc_ss 66,192 95% Pumping OIL 1,053

Cenovus Enrg Inc 102/03-29-025-20W4/00 Sep 2011 Dec 2011 Aug 2013 Kellrslie 61,891 81% Pumping OIL 1,509

Cenovus Enrg Inc 102/05-11-022-16W4/00 Dec 2012 Feb 2013 Aug 2013 Kglauc_ss 61,195 70% Flowing OIL 1,075

Cenovus Enrg Inc 103/05-01-020-15W4/00 Mar 2012 Nov 2012 Aug 2013 Mpekisko 60,971 75% Pumping OIL 1,011

Cenovus Enrg Inc 100/02-10-027-18W4/00 Jul 2011 Nov 2011 Aug 2013 Kbs_qtz 58,114 81% Pumping OIL 1,290

Cenovus Enrg Inc 103/03-36-019-15W4/00 Dec 2011 Mar 2012 Aug 2013 Kglauc_ss 57,306 72% Pumping OIL 1,008

36

Activity Summary - Cenovus Since

2011

Well Status Summary Total # of Wells Targeted Formation Total # of Wells Pumping Oil Total # of Wells

Pumping OIL 216 Kglauc_ss 113 Kglauc_ss 76

Flowing GAS 160 Kellrslie 98 Kellrslie 66

Flowing CBM Coal 61 Mpekisko 34 Mpekisko 27

Susp OIL 29 Kmannvl 28 Kmannvl 18

Flowing OIL 29 Kbelly_rv 25 Ksunburst 9

Pumping Gas 15 Kmilk_rv;Kmed_hat;K2nd_ws 21 Kbs_qtz 4

Flowing CBM & Othr 15 Kmilk_rv 20 Jrierdon 2

Susp CBM Coal 6 Undefined 14 Kostracod 2

ABD OIL Zone 6 Ksunburst 12 Kbantry 1

Commingled 6 Kmilk_rv;Kmed_hat;K2ws_ss 12 Kbs_mnvl 1

Susp GAS 5 Kmilk_rv;Kmed_hat 12 Kcolorado 1

Drlg&Cmplt OIL 2 Kmilk_rv;Kcolorado;Kmed_hat;K2nd_ws 8 Kdetrital 1

WTR Source 1 Kbs_qtz 7 Kmannvl;Kellrslie 1

ABD OIL 1 Kmilk_rv;Kmed_hat;Kmannvl 5 Kmannvl_L 1

Drlg & Completing GAS 1 Kostracod 4 Kmannvl_U 1

553 Kmilk_rv;Kvik_ss;Kglauc_ss 4 Kmilk_rv;Kmed_hat;K2ws_ss 1

Kbi_ss 4 Kmilk_rv;Kmed_hat;Kbi_ss;Kglauc_ss;Kellrslie 1

Well Type Total # of Wells Kmilk_rv;K1st_ws;Kmed_hat;K2nd_ws 4 Kmilk_rv;Kmed_hat;Kmannvl;Kglauc_ss 1

Horizontal 126 Kbsbrv_ss;Kmed_hat 4 Kvik_ss 1

Vertical 398 Kbsbrv_ss 4 Undefined 1

524 433 216

37

Glauconitic/Ellerslie Vertical Type

Curves (T27-R23)

-

50

100

150

200

250

300

0 3 6 9 12 15 18 21 24 27 30 33

Months on Production

To

tal

Pro

du

cti

on

(b

oe

/d)

Average Liquid Production

Average Total Production

All Glauconitic/Ellerslie Wells

38

Cenovus Ellerslie Hz Type Curve

-

100

200

300

400

500

600

700

800

900

1,000

0 3 6 9 12 15


To

tal

Pro

du

cti

on

(b

oe

/d)



Entice Ellerslie Hz Wells (36)

39

CVE Glauconitic Hz Type Curve

-

100

200

300

400

500

600

0 3 6 9 12 15 18 21


To

tal

Pro

du

cti

on

(b

oe

/d)



Entice Glauconitic Hz Wells (32)

40

CVE Entice Pekisko Hz Type Curve

-

100

200

300

400

500

600

0 3 6 9 12 15 18


To

tal

Pro

du

cti

on

(b

oe

/d)



Entice Pekisko Hz Wells (7)

41