April 2016 Manitok Energy Inc. is a public oil and gas exploration and development company focused on quasiconventional light crude oil in Southern Alberta and conventional light oil and gas reservoirs in the Canadian Foothills. Its trading symbols are TSXV: MEI and US OTC: MKRYF.

Reader Advisory 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". Forwardlooking 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.

2

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

Introduction - Manitok Energy Inc. (“Manitok” or the “Company”) Trading Symbols - TSXV: MEI and US OTC: MKRYF •

Based on field estimates, production was ~4,500 boe/d (46% oil) over the last 2 weeks of March 2016; •

•

With an additional 800 to 1,000 boe/d restricted or not tied-in at Carseland which is anticipated to be resolved by early in the third quarter of 2016 with $1.2 million of modifications at the recently acquired gas plant;

Manitok achieved significant reserves growth and its lowest historical one year finding costs in 2015 mainly from positive revisions on its Lithic Glauc oil reserves and a successful acquisition in SE Alberta; •

PDP reserves increased 61%, TP reserves increased 75% and P+P reserves increased 54% year over year (1);

•

Replaced 2015 production by 360% and 480% with the increase in TP reserves and P+P reserves, respectively;

•

The Company's 2015 average F&D costs and FD&A costs are $7.54/boe and $6.88/boe respectively for TP reserves. The FD&A for P+P reserves is $5.26/boe (1);

•

Q1 2016 acquisitions at Stolberg and Carseland add about $14.6 million of P+P NPV10% value(2);

•

Manitok has 92% of its 2016 anticipated oil production, net of royalties, hedged for 2016; •

•

Manitok’s oil plays have strong drilling economics at WTI US$40/bbl and higher;

• •

Hedge book (1,500 bbls/d of oil) mark to market value at ~9.4 million at April 1, 2016;

~160 drilling locations in the SE Alberta Lithic Glauc and Stolberg Cardium oil plays alone;

Manitok has gross undeveloped land of 449,900 acres with an average working interest of 94%; •

96% of total land has no production or assigned reserves. (1) PDP = Proven Developed Producing, TP = Total Proved, P+P = total proved plus probable, FDC = Future Development Capital, F&D = Finding and Development including FDC, FD&A = Finding, Development and Acquisition including FDC (2) Stolberg values derived from the Sproule 2015 reserves report. Carseland values based on internal estimates generated by Manitok Management.

4

Company Overview Corporate Snap Shot Capitalization Market Capitalization at $0.22/share

Alberta Asset Map ~$35 million

Common Shares Outstanding

161,079,746

Options

15,140,933

(W.A. exercise price of $0.69/share, 10.42 million at $0.16)

Insider Ownership

~3.5% / ~8.7%

(Basic / Fully Diluted)

Anticipated March 31, 2016 Bank Debt ($50 million credit facility) Anticipated March 31, 2016 Total Debt (1)

~$44 million ~$59 million Cordel / Stolberg

Edmonton

Asset Summary Current Production (1,200 boe/d of additional production currently shut-in)

Proved plus Probable Reserves (June 30, 2015)

Reserve Life Index

~4,500 boe/d (46% Oil)

Fallen Timber

17,626 Mboe

SE Alberta

(41% Oil)

Calgary

12.2 years

Beiseker Carseland Rockyford Strathmore Wayne

(Proved plus Probable)

Gross Total Land

482,900 acres

(93% Avg. Working Interest)

Gross Undeveloped Land

449,900 acres

Foothills Operating Area where formations have greater deformity due to folding and faulting

(94% Avg. Working Interest)

Southern Alberta Foothills

(1) Includes $15.0 million of 8-year term (~7.25 yrs. remaining) capital used to fund processing facilities.

5

Company Overview Key Acquisitions and Dispositions Set Platform for Future Growth Manitok Production Profile Gas (boe/d) Oil and Condi (bbls/d)

Disposition of dry sour natural gas assets of ~777 boe/d for $22 million

~1,100 boe/d of production restricted at Carseland due to liquids handling and Stolberg due to TCPL issues

Average Production Volumes by Quarter (boe/d)

Disposition of Swimming Heavy Oil Assets (~350 bbls/d) for $13.6 million

Entered into 3 year drilling lease, providing access to nearly 100,000 acres of land at Entice and 3D seismic data

Acquisition of Wayne assets, 1,800 boe/d (55% oil), for $61.5 million, additional 115,000 acres in SE Alberta and amended terms

6,000 5,000

1st successful Stolberg gas well, followed by a 1,300 boe/d acquisition

4,000 3,000 2,000 1,000

Q3'11 Q4'11 Q1'12 Q2'12 Q3'12 Q4'12 Q1'13 Q2'13 Q3'13 Q4'13 Q1'14 Q2'14 Q3'14 Q4'14 Q1'15 Q2'15

Q3'15 Q3'15e Q4'15

-

Historical WTI Crude Oil and NYMEX Natural Gas Pricing USD/bbl

$115

WTI Oil USD/BBL

Acquisition of SE Alberta lands

$90 $60

$30

Disposition of heavy oil assets

Acquisition of 1,300 boe/d

NNGP = US$5.00/Mcf Acquisition of Wayne assets and additional SE AB lands

Acquisition of Carseland gas plant and gathering system

Disposition of dry gas assets

NYMEX Natural Gas Price USD/Mcf 2012

2013

2014

NNGP = US$2.00/Mcf 2015

2016

6

Company Overview Great Year for Reserves Due to Acquisition and Emergence of Lithic Glauc Oil Play

Corporate Reserves – Year-End 2015 (does not include Q1 2016 acquisitions) Based on Sproule Evaluation as at December 31, 2015 - Sproule Forecast Pricing Oil (mbbl) NGL (mbbl) Natural Gas (mmcf) Proved Developed Producing (PDP) 2,699 354 17,758 Proved Developed Non-Producing

Oil Equivalent (mboe) 6,013

YOY Increase (%)

NPV 10% - BT ($mm)

61%

$88.6

298

209

6,671

1,619

$19.2

Proved Undeveloped

1,408

106

4,762

2,307

$24.1

Total Proved

4,405

669

29,191

9,939

Total Probable

2,889

403

Total Proved + Probable

7,294

1,072

26,369 55,560

75%

7,687 17,626

$131.9 $75.8

54%

$207.7

•

Replaced 2015 production by 360% and 480% with the increase in TP and P+P reserves, respectively;

•

Year over year, Manitok increased its TP reserve life index ("RLI") by 77%, to 6.9 years from 3.9 years, and its P+P RLI by 54%, to 12.2 years from 7.9 years(1)(2);

•

The Company's 2015 average F&D costs and FD&A costs are $7.54/boe and $6.88/boe respectively for TP reserves. The FD&A for P+P reserves is $5.26/boe(2);

•

Recycle ratios are 3.4x with 2015 F&D costs/boe and 3.7x with 2015 FD&A costs/boe for TP reserves, and 4.9x with 2015 FD&A costs/boe for P+P reserves (ratios are based on an average 2015 operating netback, including the realized gain or loss on financial instruments, of $25.66/boe)(2) ;

•

Recycle ratios are 1.5x with 2015 F&D costs/boe and 1.6x with 2015 FD&A costs/boe for TP reserves, and 2.1x with 2015 FD&A costs/boe for P+P reserves (ratios are based on an average 2015 operating netback, excluding the realized gain or loss on financial instruments, of $11.08/boe)(2) ;

•

Q1 2016 acquisitions of Stolberg and Carseland assets adds TP reserves of 610.3 mboe (42% oil) with a NPV10% value of $7.1 million and P+P reserves of 716.0 mboe (48% oil) with a NPV10% value of $8.7 million;

•

Reduced processing costs, post acquisition, at the Carseland gas plant also adds $5.92 million of NPV10% reserves value based on the Sproule 2015 report; total reserves value added from Q1 2016 acquisitions, on a P+P NPV10% basis, is about $14.6 million. (1)

Production rate used to calculate the 2015 RLI is based on the estimated average production rate for 2016 on PDP reserves disclosed in the 2015 Sproule Report and the 2014 RLI is based on the estimated average production rate for 2015 on PDP reserves disclosed in the 2014 Sproule Report. (2) PDP = Proven Developed Producing, TP = Total Proved, P+P = total proved plus probable, FDC = Future Development Capital, F&D = Finding and Development including FDC, FD&A = Finding, Development and Acquisition including FDC

7

Company Overview Trading at Deep Discount to P+P Net Asset Value per Share P+P Net Asset Value Non-Diluted

Diluted

P+P Reserves - Sproule Dec 31, 2015 report, NPV 10% - BT

$ 207,700,000

$ 207,700,000

Estimated P+P Reserves value from Carseland and Stolberg acquisition in Q1 2016(1)

$ 14,615,700

$ 14,615,700

Undeveloped Land Value and Seismic ($100/acre on 422,906 acres plus $10 million for 420 sq.km of 3D seismic)

$ 52,290,600

$ 52,290,600

$

$

Hedge Book Value at April 1, 2016 (see appendix)

9,416,959

9,416,959

Approximate Net Debt (includes $44 million of net bank debt and $15 million of long term debt with a remaining maturity of ~7.25 years)

$ (59,000,000)

$ (59,000,000)

Facility Financing ($20 million, 8 year term, adjusted for value of reduced Carseland gas processing fees on 2015 Sproule P+P reserves)

$ (20,000,000)

$ (20,000,000)

Production Volume Royalty NPV10% with Jan 1, 2016 Sproule Price Forecast (NPV10% value of $18.8 million with the March 23, 2016 strip price forecast)

$ (26,435,000)

$ (26,435,000)

$

$

In the Money Stock Option Exercise Value P+P Net Asset Value Number of Shares Outstanding

Net Asset Value per Share

-

1,667,360

$ 178,588,259

$ 180,255,619

161,079,746

171,500,746

$

1.11

$

(1) Stolberg values derived from the Sproule 2015 reserves report. Carseland values based on internal estimates generated by Manitok Management.

1.05

8

Company Overview Manitok Oil Play Sensitivity to Various Fixed Oil Prices

Manitok Play Type Sensitivity to Oil Price

236% 219%

210%

Carseland LG

Wayne LG

180%

175%

Cardium Basal Quartz

150%

Rate Of Return (%)

140% 128%

120%

99%

99%

90% 70% 62%

60%

56%

45%

30% 0% $35.00

21% 20%

22%

2%

$40.00

$45.00

$50.00

$55.00

$60.00

$65.00

$70.00

WTI ($US / bbl) (1) 30 day initial production rates and EUR were derived by Manitok Management using its information and public data. Assumes fixed oil prices, a fixed natural gas price of AECO $1.60/mmbtu, and a USD/CAD exchange ratio of 1.30. Assumes Manitok Management estimates of drilling costs as described on other pages of this presentation.

9

Asset Analysis | Drilling Inventory Significant NPV10% Value Even at Low Strip Oil and Gas Prices Drilling Inventory Value Greater than $1 per Share at Strip Prices Plays SOUTHEAST ALBERTA Lithic Glauc Oil (Carseland) Lithic Glauc Oil (Wayne/Rockyford) Basal Quartz Oil STOLBERG Cardium Oil Mannville Gas

Number of Net NPV 10% of Each Drilling Location(1) Risk Total NPV 10% Locations ($Millions) Adjustment ($Millions) 28 131 137

$2.0 $0.9 $0.34

85% 70% 85%

$47.6 $82.5 $39.6

9.6 9.3

$1.3 $1.0

90% 85%

$11.2 $ 7.9

Total Net Present Value Total Net Present Value / Share Diluted 2P NAV / Share Total Potential Value / Share

$188.8 $1.17 $1.05 $2.22

(1) 30 day initial production rates and EUR were derived by Manitok Management using its information and public data. Assumed 5

year strip pricing as of March 23, 2016 (see appendix) with a 2% annual price escalation after the 5 years.

10

Asset Analysis | SE Alberta - Lithic Glauc Oil Most of the Lithic Glauc Drilling Upside not Booked in 2015 Sproule Reserve Report 159 Hz Lithic Glauc Drilling Locations

1

Beiseker

Wayne 1-20 Battery

2

NOVA PIPELINE

3

Strathmore

 Wayne  IPL PIPELINE

4 Rockyford ATCO PIPELINE



   

Focusing on the Lithic Glauc play in 2016 given the stronger economics and drilling success at Carseland; Large OIP in all 5 areas – 4 areas equivalent or better reservoir thickness than Carseland; Excellent well control with bypassed pay indicated on logs in all 5 areas; Similar or better porosity than at Carseland; 3D seismic compares favorably to Carseland; Two farmins/JVs in place, with 2 separate parties; one in Rockyford and one in Beiseker; SE Alberta freehold lands with 17.5% royalty;

Lithic Glauc Reservoir Characteristics Carseland

4-32 Battery

Carseland 16-21 Gas Plant

Carseland 28 # of Hz Drilling Locations 22 Gross Sand Thickness (m) Net Pay (m) 14

Area 1 42

Area 2 24

Area 3 8

Area 4 36

28

23

27

31

23

14

22

24

Porosity

9-10%

9%

9-12%

9-12%

9-11%

11

Asset Analysis | Carseland - Lithic Glauc Oil Recent Gas Plant Acquisition will Facilitate Rapid Production Growth in the Area Carseland Area Map

Lithic Glauc Economic at Low Oil Prices _   

  

Operator and 100% working interest; Acquired 14 MMcf/d gas plant on March 4th ; Increased production in the area during March from 590 boe/d (32% oil) to 940 boe/d (26% oil) with minor modifications to the gas plant since acquisition; Only 5 of 7 Hz wells currently on production with two still at significantly restricted rates and two BQ wells to be tied-in over Q3 2016; Total horizontal drilling inventory of 28 Lithic Glauc wells and 28 Basal Quartz wells at Carseland; Anticipate a drilling program focused on Lithic Glauc oil in Q4 2016.

Carseland Glauc Oil - Hz Well Economics Total Hz Cost (D, C & E)

$1.77 MM

30 Day IP Rate (42% - 39° API oil) (1)

425 boe/d

EUR (42% oil) (1)

385 Mboe

BT NPV10

$2.16 MM

BT IRR (1)

74%

Recycle Ratio / Payout Potential 2016 Drills (100% WI) (1) 30 day initial production rates and EUR were derived by Manitok Management using its information and public data. Assumes 5 year strip pricing as of March 23, 2016 (see appendix) with a 2% annual price escalation after the 5 years. Assumes Manitok Management estimates of drilling costs based on a 1,400m Hz wellbore.

2.5x / 1.5 yr. 2-4

12

Asset Analysis | Wayne - Lithic Glauc Oil Economic to Drill Wayne Lithic Glauc Play at Current Low Oil Prices Wayne Area Map

Lithic Glauc Economic at Lower Oil Prices__  

  

Operator and 100% working interest in the area; Total horizontal drilling inventory of 74 Lithic Glauc wells, with 42 locations within 10 miles of the Manitok operated 1-20 Wayne oil battery (see appendix for details on battery); Similar geology to Carseland, confirmed with analysis of well logs, drill cuttings and 3D seismic; 81 Basal Quartz drilling locations; Anticipate a drilling program focused on Lithic Glauc oil wells in Q4 2016.

Wayne Glauc Oil - Hz Well Economics Total LG Hz Cost (D, C & E)

$1.77 MM

30 Day IP Rate (58% - 39° API oil) (1)

295 boe/d

EUR (58% oil) (1)

223 Mboe

BT NPV10

$0.92 MM

BT IRR (1)

39%

Recycle Ratio / Payout

1.7x / 2.1 yr.

Potential 2016 Drills (100% WI) (1) 30 day initial production rates and EUR were derived by Manitok Management using its information and public data. Assumes 5 year strip pricing as of March 23, 2016 (see appendix) with a 2% annual price escalation after the 5 years. Assumes Manitok Management estimates of drilling costs based on a 1,400m Hz wellbore.

1-2

13

Asset Analysis | Cordel / Stolberg (Manitok Operated) Stolberg Upside Increased with Acquisition and Anticipated EOR Plan Production & Reserves Upside_ 



Identified potential initial production upside of ~10,000 boe/d (30% oil) with 33 (18.9 net) drilling locations:  Cardium Oil – 19 (9.6 net) wells ~3,300 net boe/d  Mannville Gas – 14 (9.3 net) wells ~6,900 net boe/d Enhanced Oil Recovery plan – F Pool and N pool  Potentially 2.5 MMbbls of additional recoverable oil in F pool assuming a 24% recovery factor;  No waterflood bbls booked to 2015 reserves report;

Cardium Oil - Hz Well Economics

Total Hz Cost (D, C & E) 30 Day IP Rate (80% oil)

(1)

345 boe/d 266 Mboe

EUR (1) BT NPV10 (risked) BT IRR (risked)

$3.0 MM

$1.3 MM

(1)

38%

Recycle Ratio / Payout

2.0x / 1.7 yrs.

Possible 2016 Drills

0 - 1 (0.3 net)

Mannville Gas - Hz Well Economics

Total Hz Cost (D, C & E)

30 Day IP Rate (6% oil)

(1)

$3.5 MM

4.5 Mmcfe/d 6.2 Bcfe

EUR (1) BT NPV10 (risked) BT IRR (risked)

$1.0 MM

(1)

Recycle Ratio / Payout

18% 1.2x / 3.9 yrs.

Possible 2016 Drills (1) 30 day initial production rates and EUR were derived by Manitok Management using its information and public data. Assumes 5 year strip pricing as of March 23, 2016 (see appendix) with a 2% annual price escalation after the 5 years. Assumes Manitok Management estimates of drilling costs based on a 400m to 600m Hz wellbore.

0-1

14

Asset Analysis | Cordel / Stolberg Low Cost Reserves add at Stolberg Cardium F Pool - EOR Project Stolberg Cardium F Pool Oil Production Rate History and Forecasts

Stolberg Cardium F Pool Cumulative Oil Production History vs Forecasts

Cumulative Oil to Date –1,350 mbbl - 7% RF Est. Primary Depletion – 1,840 mbbl - 10% RF EOR - Waterflood with Gas Reinjection – 4,350 mbbl - 24% RF Incremental Reserves of 2,510 mbbl over Primary Depletion

Enhanced Oil Recovery plan – F Pool and N Pool  3rd party engineering simulations suggest an increase in the oil recovery factor from 9% to 24%  ~2.5 million bbls of additional recoverable oil in F pool alone. 15

Manitok Well Economics with Bullish View of Oil Prices Significant Leverage to a Recovery in Commodity Prices Carseland Glauc Hz Oil Well Economics

Total Hz Cost (D, C & E)

$1.77 MM

Wayne Glauc Hz Oil Well Economics

Total LG Hz Cost (D, C & E)

$1.77 MM

(1)

30 Day IP Rate (42% - 39° API oil) (1)

425 boe/d

30 Day IP Rate (58% - 39° API oil)

EUR (42% oil) (1)

385 Mboe

EUR (58% oil) (1)

223 Mboe

$4.4 MM

BT NPV10

$2.6 MM

145%

BT IRR (1)

93%

BT NPV10 BT IRR

(1)

Recycle Ratio / Payout

3.0x / 1.0 yr.

Recycle Ratio / Payout

295 boe/d

2.1x / 1.3 yr.

BQ Oil Hz Well Economics Total BQ Hz Cost (D, C & E) 30 Day IP Rate (63%-30° API oil) (1) EUR (63% oil) (1) BT NPV10 BT IRR (1) Recycle Ratio / Payout

Cardium Oil Hz Well Economics

$1.64 MM 199 Boe/d 159 Mboe $1.7 MM 59% 1.7x/1.8 yrs.

Mannville Gas Hz Well Economics

Total Hz Cost (D, C & E)

$3.0 MM

Total Hz Cost (D, C & E)

$3.6 MM

30 Day IP Rate (80% oil) (1)

345 boe/d

30 Day IP Rate (6% oil) (1)

4.5 Mmcfe/d

EUR (1)

266 Mboe

EUR (1)

4.8 Bcfe

BT NPV10 (risked)

$2.8 MM

BT NPV10 (risked)

$3.8 MM

BT IRR (risked) (1)

73%

BT IRR (risked) (1)

42%

Recycle Ratio / Payout

2.5x / 1.1 yrs.

Recycle Ratio / Payout

2.4x / 2.3 yrs.

(1) 30 day initial production rates and EUR were derived by Manitok Management using its information and public data. Assumes Sproule’s January 1, 2016 price deck (see appendix). Assumes Manitok Management estimates of drilling costs based on a 1,400m Hz leg for Glauc , 1,000m Hz leg for BQ and a 400m to 600m Hz leg for the Cardium and Mannville.

16

Asset Analysis | Potential Value of Drilling Inventory ~$600 Million of Drilling Upside with Bullish Oil Price Perspective Total NPV Triples with a Recovery in Commodity Prices to the Sproule Price Deck Level Number of Net NPV 10% of Each Drilling Location(1) Locations ($Millions)

Plays Southeast Alberta Lithic Glauc Oil (Carseland) Lithic Glauc Oil (Wayne/Rockyford) Basal Quartz Oil Stolberg Cardium Oil Mannville Gas

Risk Total NPV 10% Adjustment ($Millions)

28 131 137

$4.4 $2.6 $1.7

85% 70% 85%

$104.7 $238.4 $198.0

9.6 9.3

$2.8 $3.8

90% 85%

$24.2 $30.0

Total Net Present Value Total Net Present Value / Share Diluted 2P NAV / Share Total Potential Value / Share

$595.3 $3.70 $1.05 $4.75

(1) 30 day initial production rates and EUR were derived by Manitok Management using its information and public data. Assumed

Sproule price deck as of January 1, 2016 (see Appendix).

17

Appendix

18

Sproule Price Deck - January 1, 2016 SPROULE ASSOCIATES LTD.

SUMMARY OF PRICE FORECASTS, INFLATION and EXCHANGE RATES

Year

Light Crude Oil 1 WTI Canadian Cushing Light Sweet Oklahoma 40 API $US/Bbl CAD$/Bbl

Natural Gas and Liquids

Henry Hub Ethane Price AECO - C Spot Plant Gate $US/MMbtu CAD$/MMbtu CAD$/Bbl

Edmonton Propane CAD$/Bbl

Edmonton Butane CAD$/Bbl

Edmonton Pentanes Plus CAD$/Bbl

Exchange Rate $US/$Cdn

2016 12 mo. Est

45.00

55.20

2.25

2.25

6.23

9.09

39.09

59.10

0.750

2017

60.00

69.00

3.00

2.95

8.17

13.64

51.43

73.88

0.800

2018

70.00

78.43

3.50

3.42

9.47

25.84

58.46

83.98

0.830

2019

80.00

89.41

4.00

3.91

10.82

35.35

66.64

95.73

0.850

2020

81.20

91.71

4.25

4.20

11.64

42.30

68.35

98.19

0.850

2021

82.42

93.08

4.31

4.28

11.85

42.94

69.38

99.66

0.850

2022

83.65

94.48

4.38

4.35

12.06

43.58

70.42

101.16

0.850

2023

84.91

95.90

4.44

4.43

12.27

44.24

71.48

102.68

0.850

2024

86.18

97.34

4.51

4.51

12.49

44.90

72.55

104.22

0.850

2025

87.48

98.80

4.58

4.59

12.71

45.57

73.64

105.78

0.850

2026

88.79

100.28

4.65

4.67

12.93

46.26

74.74

107.37

0.850

Escalation Rate of 1.5% Thereafter 1.40 Deg API, 0.4% Sulphur

19

Strip Commodity Price Deck – March 23, 2016

Created March 23, 2016

Mid-market as of close of business 22-03-16 CAL16

AECO CAD/GJ

NYMEX NG USD/MMBtu

WTI USD/Bbl

WTI CAD/Bbl

CAD/USD

$1.697

$2.202

$43.88

$57.22

$1.304

CAL17

$2.527

$2.739

$46.31

$60.25

$1.301

CAL18

$2.660

$2.803

$47.86

$62.02

$1.296

CAL19

$2.783

$2.843

$48.92

$63.09

$1.290

CAL20

$2.919

$2.920

$49.79

$63.92

$1.284

DISCLAIMER : National Bank of Canada and its affiliates is acting solely in the capacity of an arm’s length contractual counterparty, and not as an adviser or fiduciary. Accordingly you should not regard transaction proposals or other written or oral communications from us as a recommendation or advice that a transaction is appropriate for you or meets your financial objectives. Any financial transaction involves a variety of potentially significant risks and issues. Before entering into any financial transaction, you should ensure that you fully understand the terms, have evaluated the risks and determined that the transaction is appropriate for you in all respects. You should consult appropriate financial and legal advisers before entering into the transaction. The attached material does not constitute an offer to enter into any transaction. Such material is believed by us to be reliable, but we make no representation as to its accuracy or completeness. This brief statement does not purport to describe all of the risks associated with financial transactions and should not be construed as advice to you. Weather updates comes from an independent service.

20

Introduction Experienced Management Team Massimo Geremia President & CEO

26 years of public company experience in Oil and Gas, Real Estate and Finance; previously with Birchcliff Energy Ltd., Equatorial Energy Inc. & Boardwalk Equities Inc.

Cameron Vouri, P. Eng. COO

Over 25 years of experience; former President Upstream Canadian Oil and Gas Business unit at Provident Energy Trust; instrumental in the growth of Provident from 3,000 to 30,000 boe/d

Robert Dion, C.A. VP Finance & CFO

25 years of industry experience in senior financial positions at Canadian Natural Resources Ltd., Rio Alto Exploration Ltd. and Nexen Inc.

Tim Jerhoff, P. Eng. VP Production and Engineering

Over 25 years of experience with Encana, Provident Energy Trust and Richland Petroleum; most recent role was as Manager, Clearwater South Production at Encana where he was responsible for 30,000 boe/d and an annual capital program of over $100 million

Don Martin, B.Sc. Honours VP Exploration

Over 30 years of progressive geoscience experience; previously with Evergreen Resources, Marathon Canada, Anderson Exploration and Pan Canadian Petroleum.

Robert Brown M.Sc.

20 years of industry experience; previously with Talisman Energy and Vermillion Resources Ltd.

Sr. Manager Business Development

21

Introduction Board of Directors Bruno Geremia

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

Massimo Geremia

President & CEO, Manitok Energy (MEI – TSXV)

Keith McLeod, P.Eng.

Former Director, Partner, and CEO of Sproule Associates Ltd.

Dennis Nerland, Q.C

Partner, Shea Nerland Calnan LLP; Director of Crew Energy Inc. (CR-TSX)

Greg Peterson

Partner, Gowlings Canada

Tom Spoletini

Independent Businessman in Calgary.

Cameron Vouri, P.Eng.

COO, Manitok Energy Inc. (MEI – TSXV), formerly with Provident Energy Trust

22

Company Overview Hedging Value at April 1, 2016 Hedge Book Product Oil Oil Oil Oil

Notional Quantity 500 bbls/d 500 bbls/d 500 bbls/d 500 bbls/d

Contract Term January 1, 2016 to December 31, 2016 January 1, 2017 to December 31, 2017 January 1, 2016 to December 31, 2016 January 1, 2016 to December 31, 2016

Price Reference Average Strike CAD$ WTI CAD$ WTI CAD$ WTI CAD$ WTI

$80.15 $80.15 $75.00 -$90.00 $70.00 -$90.00

Contract Swap Option(1) Collar(2) Collar(3)

(1)The counter-party to this contract holds a one-time option no later than December 31, 2016 to extend a swap on 500 barrels per day of oil at CAD$80.15 for the period indicated (2)Manitok recorded $1.6 million as a deferred premium on financial instruments in Q2/15, which represents the amount payable to the counter- party on these contracts for the deferred option collar premium of $4.50 per barrel (3)Manitok recorded $1.2 million as a deferred premium on financial instruments in Q2/15, which represents the amount payable to the counter- party on these contracts for the deferred option collar premium of $3.15 per barrel

Hedge book mark to market value at ~$9.4 million on April 1, 2016 Mark to market value was at ~$15.6 million on February 10, 2016 (USD WTI at about US$29.66)

23

Asset Analysis | Wayne Oil Facility Wayne Facility Provides Greater Control of Operations and Production 

Wayne facility was acquired in Manitok’s June 2015 acquisition  Wayne 1-20 battery and acid gas injection integrated with 8-23 satellite  Oil treating 9,400 bbls/d, truck-in 72 loads/d and acid gas disposal  Emulsion handling >31,000 bbls/d, water disposal 26,000 bbls/d



Fluid handling process  Trucked-in emulsion is treated at Wayne 1-20  Clean oil pipelined to IPF lact unit – 6,600 bbls/d capacity  Clean water pipelined to 8-23 for disposal/injection  Nisku & BQ production tied in to 8-23 satellite  Water stripped off and injected  Residual emulsion treated at 1-20 Battery  Solution gas pipelined to 1-20 acid gas plant Battery and plant constraints  Acid gas – amine design capacity 15-18 MMcf/d  Current capacity 4.4 MMcf/d constrained by compression  Water disposal and injection – 26,000 bbls/d  Currently constrained by injection pump capacity  Currently injecting into 6 Nisku & Leduc wells at low pressure  1-23 Battery truck-in – recently upgraded in 2013  Shift schedule dependent, 12 hr or 24 hr operation



24

Asset Analysis | SE Alberta - Basal Quartz Oil Most of the Upside in Reserves with BQ Drilling Inventory not Booked 137 Hz Basal Quartz Drilling Locations Wayne 1-20 Battery

Beiseker

Wayne



28 Hz drilling locations at Carseland; 81 locations at Wayne and 28 locations in Beiseker and Strathmore areas



The above locations are based on spacing of 4 Hz wells per section; may require 8 Hz wells per section in order maximize reserve recovery



Other zones of interest on lands include Viking, upper Mannville, Ostracod, Pekisko and Nisku.

NOVA PIPELINE IPL PIPELINE

Strathmore

Rockyford

ATCO PIPELINE

Basal Quartz Oil - Hz Well Economics Carseland 4-32 Battery

Carseland 16-21 Gas Plant

Total BQ Hz Cost (D, C & E)

$1.64 MM

30 Day IP Rate (63% - 30° API oil) (1)

199 Boe/d

EUR (63% oil) (1)

159 Mboe

BT NPV10

$0.34 MM

BT IRR (1)

20%

Recycle Ratio / Payout

1.4x / 3.2 yrs.

Potential 2016 Drills (100% WI) (1) 30 day initial production rates and EUR were derived by Manitok Management using it’s information and public data. Assumes 5 year strip pricing as of March 23, 2016 (see appendix) with a 2% annual price escalation after the 5 years. Assumes Manitok Management estimates of drilling costs based on a 1,000m Hz wellbore.

0-1

25

Stolberg Cardium F Pool - EOR Project TVD (m) 1200

Cardium F Pool Gas Cape Height ~275 meters

1350

Horizontal Gas Injector well used to inject associated gas back into reservoir.

1500

CURRENT GAS OIL CONTACT

1650 Cardium Sand Reservoir Thickness ~15 meters

533m

1800

Cardium F Pool Oil Column Height ~450 meters

OIL WATER CONTACT 100/12-21

Horizontal Water Injector well to inject water into the lower part of the reservoir

4 Horizontal Oil Producers 1 Horizontal Oil Reactivation Average Horizontal Length: 550m

1950

2100

2250

2400

26

Exceptional Exploration Success Proves Up Plays Top 10 Horizontal Glauconitic Producing Wells in Southern Alberta Rank

Unique Well ID

1 2 3 4 5 6 7 8 9 10

100/16-32-022-25W4/00 102/15-23-019-14W4/00 102/13-25-019-15W4/02 100/15-32-022-25W4/00 102/10-21-015-12W4/00 100/13-29-023-13W4/00 103/13-12-017-11W4/00 103/01-02-020-15W4/02 100/13-05-020-14W4/00 100/02-15-017-12W4/00

IP 30

IP 60

820 808 787 760 714 696 643 621 550 543

750 705 488 682 349 610 450 506 221

IP 90 Current Operator Name 463 441 458 288 506 331 387 136

Manitok Husky Cenovus Manitok Cenovus Journey Cenovus Cenovus Cenovus Cenovus

Spud Date 18-Sep-14 13-Jan-14 25-Jan-11 26-Jun-14 02-Jan-14 25-Aug-12 28-Oct-11 30-Jan-12 19-Jul-14 27-Jan-14

Note: 15-32-22-25W4 IP30 rate is the 6 day average production test rate.

Top 10 Horizontal Basal Quartz Producing Wells in Southern Alberta Rank

Unique Well ID

1 2 3 4 5 6 7 8 9 10

100/01-10-027-18W4/00 102/16-27-026-18W4/00 102/14-27-027-20W4/00 100/14-33-022-25W4/00 100/15-36-028-16W4/00 102/14-13-018-10W4/00 102/15-27-026-18W4/00 100/13-26-026-18W4/00 102/13-15-027-18W4/00 100/09-02-027-18W4/00

IP 30

IP 60

831 735 642 604 559 548 525 515 485 478

655 573 549 445 262 315 547 490 721 577

IP 90 Current Operator Name 648 487 341 305 270 473 566 588

Cenovus Cenovus Cenovus Manitok Traverse Imaginea Cenovus Cenovus Cenovus Cenovus

Spud Date 26-Sep-12 26-Jan-13 17-Oct-13 04-Oct-14 28-Sep-14 20-Oct-12 03-Sep-12 07-Oct-14 14-Sep-11 03-Jun-14

27

Lithic Glauc Oil Analog Wells Drilled by Cenovus Cenovus Hz Drills 2010-2013 Bantry/Cessford/Countess Glauconitic(1) 600

2010

2011

2012

Initial Production 90 days (boe/d)

500

2013

NCS Multistage (uncemented, “Hybrid”) NCS Multistage (cemented) PP StackFRAC No Record

400

300

Average 90 day Initial Production Rate of 210 boe/d on 28 wells 200

100

0

1)

Data compiled by Manitok from: Geoscout, Canadian Discovery.

28

600

200

100/4-16-27-19W4/0 100/13-28-27-20W4/0 102/14-28-27-20W4/0 100/4-32-26-18W4/0 100/16-15-27-18W4/0 100/2-10-27-18W4/0 105/7-8-27-19W4/0 106/7-8-27-19W4/0 102/13-15-27-18W4/0 102/14-20-25-20W4/0 100/16-9-27-18W4/0 100/14-10-27-18W4/0 103/6-4-26-19W4/0 102/2-20-25-20W4/0 102/3-29-25-20W4/0 100/8-17-26-19W4/0 100/15-8-25-20W4/0 100/10-16-25-17W4/2 100/13-6-25-18W4/0 100/3-7-24-17W4/0 102/16-27-27-20W4/0 100/15-27-27-20W4/0 100/1-10-27-18W4/0 103/10-12-25-20W4/0 100/15-29-25-20W4/0 102/1-20-25-20W4/0 100/10-10-26-17W4/0 100/3-9-26-19W4/0 102/16-21-27-18W4/0 102/15-27-26-18W4/0 102/14-16-27-19W4/0 100/4-11-27-18W4/0 100/3-16-27-18W4/0 103/13-16-27-19W4/0 102/14-27-26-18W4/0 100/3-11-26-17W4/0 102/1-10-26-17W4/0 102/4-21-27-19W4/0 100/13-27-26-18W4/0 100/3-21-27-19W4/0 103/16-21-27-18W4/0 102/16-27-26-18W4/0 100/6-8-25-18W4/0 100/11-1-25-20W4/0

Initial Production 90 days (boe/d)

Basal Quartz Oil Analog Wells Drilled by Cenovus Cenovus (CVE-TSX) Wayne BQ Hz Drills 2010-2013(1) 800

700

2010 2011

1)

2012

Data compiled by Manitok from: Geoscout, Canadian Discovery.

NCS Multistage (uncemented, “Hybrid”)

NCS Multistage (cemented) PP StackFRAC No Record

2013

500

400

300

Average 90 day Initial Production Rate of 198 boe/d on 44 wells

100

0

29