Manitok Energy Inc. (MEI TSXV) Corporate Presentation June 2014
Reader Advisory 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". 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 forwardlooking 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
The Corporate Company Snapshot MEI on TSX-V Market Capitalization at $2.30/share Common Shares Outstanding at May 27, 2014 Options (wgt avg exercise price of $2.09/share) Insider Ownership, Undiluted / Diluted Net Debt at Mar 31/14 ($105MM Credit Facility) ~ $170 million 70,277,274 5,290,074 6.7% / 10.3% $26.6 million Average April 2014 Production ~ 4,900 boe/d (67% Oil) (1) Proved plus Probable Reserves Dec 31/13 Reserve Life Index (proved plus probable) Gross Total Land (94% Avg Working Interest) Gross Undeveloped Land (96% Avg Working Interest) 12,149.5 Mboe (65% Oil) (1) 6.7 yrs (1) 310,000 acres (1) 295,000 acres (1) 97% of ~291,000 net acre land position is undeveloped 1. Adjusted for the disposition of 777 boe/d of production, 4,570 Mboe of 2P reserves, and associated lands announced on February 27, 2014 and closed February 28, 2014. 4
Successful Corporate Strategy Focus on Areas with Underexploited Conventional Reservoirs A successful strategy used in the industry for decades; Less reliance on new equity to drive production and reserves growth due to short pay back periods and lower decline rates; Establish Large Land Positions in Areas with a Competitive Advantage ~184,000 gross undeveloped acres (94% average working interest) in the Foothills where industry activity has been limited since 2008; ~96,800 contiguous acres (100% working interest) in SE Alberta with multi-zone potential which are underexploited and competition is limited due to freehold lease; Corporate Goals Increase proportion of oil production; Maintain call option on natural gas by building an inventory of drilling opportunities to exploit when gas prices support strong rates of return; Maintain debt to cash flow ratio of less than 1.25 times; Achieve corporate production of 20,000 boe/d in the next 5 years through both growth from the drill-bit and accretive acquisitions; 5
Exceptional Production Growth Gas (boe/d) Oil & liquids (bbls/d) Disposition of Swimming Heavy Oil Assets (~350 bbls/d) Average Production Volumes by Quarter (boe/d) Successful Redeployment of Disposition Capital Disposition of Central AB Natural Gas Assets (~777 boe/d) 8,000 7,000 6,000 5,000 4,000 1 st successful Stolberg gas well, followed by 1,300 boe/d Acquisition 3,000 2,000 1,000 Q3'10 Q4'10 Q1'11 Q2'11 Q3'11 Q4'11 Q1'12 Q2'12 Q3'12 Q4'12 Q1'13 Q2'13 Q3'13 Q4'13 Q1'14e Q2'14e Q3'14e Q4'14e - 1) Estimates are derived from Manitok s 2014 guidance as provided in the following slide. 6
Growth Per Share Continues in 2014 At $2.30 per share (June 2nd, 2014), MEI is trading at 2.4x forecast 2014 cash flow. 2012 Actual 2013 Actual Annual Increase 2014 Guidance Annual Increase Production Annual (boe/d) 2,389 4,113 72% 6,000 6,200 48% % Oil and liquids 40% 52% 30% 62% - 65% 22% Exit rate (boe/d) 3,860 5,550 44% 7,100 7,500 32% % Oil and liquids 42% 58% 38% 67% 70% 18% Annual Production per Thousand Shares (boe) 13.5 20.7 53% 30.5 47% Benchmark pricing Crude oil WTI (US$) 97.98 92.00 $CAD/$US exchange rate 1.03 1.06 Crude oil WTI ($CAD) 100.92 97.52 Differential WTI ($CAD) to Realized (11.17) (10.77) Natural gas AECO daily spot ($/mmbtu) 3.18 3.30 Netbacks Operating ($/boe) 25.59 33.07 29% 34.43 4% Funds from operations ($/boe) 21.82 27.68 27% 30.83 11% Funds from operations 19.1 million 41.6 million 118% 69 71 million 68% Funds from operations per share $0.30 $0.59 97% $0.96 63% Net Capital expenditures 44.2 million 79.4 million 80% 93.1 million 17% Net debt at year end 10 million 32.5 million 225% 58 million 79% 7
Net Asset Value MEI on TSX-V May 27, 2014 Net Asset Value Calculation (diluted) Proved plus Probable Reserves Dec 31, 2013 - NPV 10% (excluding disposition announced on February 27th, 2014) (1)(2) $ 268,793,000 Undeveloped Land Value ($150/acre for land on 283,200 net acres) (3) $ 42,480,000 Estimated Working Capital (Net Debt) at May 27, 2014 $ (35,000,000) Options Exercise Value (5,290,074 options at $2.09 average exercise price) $ 11,062,996 Net Asset Value $ 287,335,996 Number of Fully Diluted Shares Outstanding 75,567,348 Net Asset Value per Diluted Share $ 3.80 Current Share Price $ 2.30 Discount to Net Asset Value 40% 1) Estimates of future net revenues whether discounted or not do not represent fair market value 2) Net Present Values ( NPV ) equals net present value of future net revenue before taxes based on Sproule s forecast prices and costs as at December 31, 2013. 3) Internally estimated by Manitok Management. 8
RRX BNE SPE TOG RMP CJ SGY ARN CR GXE ZAR DTX LEG RE HYX TVE LNV SOG OIL TBE MQL LRE CKE YGR AEI PRY PXL MEI EV / 2014E DACF (x) Outstanding Value Cheap! 10.0x ATTRACTIVE DEBT ADJUSTED CASH FLOW MULTIPLE EV / 2014E DACF (1)(2) 9.0x 8.0x 7.0x 6.0x Avg. EV / 2014E DACF: 5.6x 5.0x 4.0x MEI 3.0x 2.0x 1.0x 0.0x 1) Estimates as per NBF or Industry Research 2) Estimates adjusted to reflect NBF commodity pricing based on the May 1, 2014 forward strip (2014E: WTI US$98.25/bbl, Natural Gas C$4.95/mcf, $US/$CAD 1.101) 3) The comparison companies in the analysis above are listed in the Appendix 9
CJ DTX RE TVE YGR MEI RRX CKE RMP TOG SOG BNE SPE CR AEI MQL LNV OIL TBE ZAR LRE LEG SGY GXE PRY PXL HYX ARN Debt / 2014E Cash Flow (x) Pristine Balance Sheet Low Risk FINANCIAL STRENGTH AND FLEXIBILITY CURRENT NET DEBT / 2014E CASH FLOW (1)(2)(3) 5.0x 4.0x 3.0x 2.0x Avg. Net Debt / 2014E CF: 1.6x 1.0x MEI 0.0x 1) Estimates as per NBF or Industry Research 2) Estimates adjusted to reflect NBF commodity pricing based on the May 1, 2014 forward strip (2014E: WTI US$98.25/bbl, Natural Gas C$4.95/mcf, $US/$CAD 1.101) 3) Net debt used in the calculation of current net debt / forward cash flow does not reflect any reductions due to options / dilutive proceeds 4) The comparison companies in the analysis above are listed in the Appendix 10
Normal Course Issuer bid (NCIB) - Growth Through Acquisition Number of Shares Price / Share Total Dollars NCIB from Nov. 8, 2013 to May 27, 2014 (7,482,900) $ 2.39 $ (17,899,723) Exercised Stock Options 1,730,034 $ 1.37 $ 2,377,885 Net Increase (Decrease) (5,752,866) $ (15,521,838) Per Share, Pre NCIB, Based on 76,030,140 Shares O/S Per Share, Post NCIB, Based on 70,277,274 Shares O/S Net Accretion "Acquired" Assets Through NCIB Purchase Metrics @ $0 Land Value Purchase Metrics @ $150/acre Land Value Est. 2014 Average Production, boe/d (based on guidance) 6,100 0.0293 0.0317 8.2% 499 boe/d $ 31,085 $ 24,121 per flowing boe Est. 2014 Exit Rate Production, boe/d (based on guidance) 7,500 0.0360 0.0390 8.2% 614 boe/d $ 25,282 $ 19,618 per flowing boe Estimated 2014 Cash Flow (based on guidance) $70 mil. $ 0.9207 $ 0.9961 8.2% $ 5,730,168 / yr. 2.7 2.1 x CF multiple Undeveloped Land, Net acres 283,200 0.0037 0.0040 8.2% 23,183 acres $ - $ 3.48 mil. of Land Value 11
The People Board of Directors Bruno Geremia, C.A. - Chairman VP Finance & CFO, Birchcliff Energy (BIR TSE) Robert J. Dales Director of Kelt Exploration (KEL-TSX) and 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 in Calgary Cameron Vouri, P.Eng. COO, Manitok Energy (MEI TSX); previously President of Provident Energy Trust s Canadian business unit 12
Experienced Management Team 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; 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.; Tim Jerhoff, P.Eng., VP Production and Engineering Over 25 years of experience in the Canadian oil and gas industry 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 a capital program of over $100 million; 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; Robert Brown M. Sc., Senior Manager Business Development 17 years of industry experience; previously with Talisman Energy and Vermillion Resources Ltd. 13
Up to 100% Production Growth Upside Remaining at Stolberg Future drilling locations at Stolberg: 8 Cardium oil wells into backlimb; 4 Cardium oil wells into new pool; 10 Cardium oil wells into forelimb; 3 Mannville natural gas wells; Up to 3,500 to 5,000 net boe/d (57% oil) of identified production upside remaining: Cardium Oil 22 (9.1 net) locations; +3,450 net boe/d unrisked; +2,400 net boe/d risked at 70%; Mannville Gas 3 (2.25 net) locations +1,600 net boe/d unrisked; +1,120 net boe/d risked at 70%; Water flood could increase the recovery factor from 9% to potentially 20%. Total Cardium Hz Cost (DC, C & E) $4.8 MM 30 Day IP Rate (80% oil)* 380 Boe/d EUR* BT NPV10 (risked at 70%) 380 Mboe $5.7 MM BT IRR* (risked at 70%) 108% Recycle Ratio / Payout Planned 2014 Drills 3.7x / 1.1 yrs. 16 (~7.9 net) Cordel Cordel Water Flood 2014 drilling program Stolberg * 30 day initial production rates and EUR were derived by Manitok Management using an average actual results to date on all wells drilled to the end of 2013 at Stolberg and Manitok s 2013 reserves report. The Price deck used to calculate the IRR is in the appendix. 14
Stolberg Continue to Find New Pools on the Old Structure Backlimb - ~85% of production and drilling to date has been delineating the main backlimb of the Stolberg structure. Drilling the backlimb in the heart of the field, where the fracturing is greatest, now and over the summer. Forelimb - Three well penetrations at the south end of the field have discovered an oil bearing forelimb that contains similar reservoir qualities as the backlimb; two of these southern forelimb wells have cumulatively produced >110,000 bbls to date. New Sheet / Pool Discovery - 2 wells drilled into the new pool (1 in sect 21 & 1 in sect 29) in 2013 each initially flowed at rates greater than 500 boe/d. The continuation of this trend to the south will be tested with drilling late in June 2014. New Pool Backlimb Forelimb A recently drilled pilot hole, in the central part of the Stolberg field, tested Cardium oil in the forelimb. The results showed the Cardium forelimb s thickness is consistent with that found in most of the backlimb which is where most of the production from the structure has been from to date. The formation is oil bearing and at original reservoir pressure, which indicates a possible new pool discovery within the larger structure. A well will be drilled to test this potential new discovery early in the fourth quarter. Water flood at both Cordel and Stolberg - AER has approved Cordel water flood plan which will provide information for an eventual water flood of the Stolberg pool. Cordel water flood to begin over the summer of 2014. A successful water flood at Stolberg could increase oil recovery from 9% to 20%. 15
Large Scale Opportunity at Entice New Pool Log Leads 55 have been identified. Viking Glauconitic Ellerslie / BQ Pekisko Nisku Wabamun 28 27 26 25 24 23 Twp 22 Wbmn Swalwell D-1 A Pool Cum 4 MMBO 59 Wells, 1996 R 25 Underexploited - Only 250 well penetrations in the Mannville or deeper; Full 3D seismic coverage over entire block (> 400 sq. miles); 55 new pool log leads identified; New pool discoveries will lead to an increased drilling inventory over time. Calgary BQ (Elrl) Entice B Pool Cum 5 MMBO 39 Wells, 1987 24 Strathmore 23 Swallwell Nisku Pools Cum 5 MMBO 17 wells, 1969 Mannville well density plotted on map Glcc A-C Pool Cum 3.7Bcf & 370 MBO 4 Wells, 1979 Glcc F Pool Cum 6 MMBO 20 Wells, 1987 Glcc A Pool Cum 1.2 MMBO 9 Wells, 1992 Nsku Wayne A Pool Cum 11 MMBO 40 Wells, 1993 Glcc Blackfoot D Pool Cum 7 Bcf & 741 MBO 9 Wells, 1995 Wayne-Rosedale BQ (Ellerslie) Recent Cenovus Hz drilling activity Glcc Hussar A Pool Cum 26 MMBO 46 Wells, 1958 Over 200 MMbbls of cumulative oil production and 12 Tcf of cumulative gas production in the surrounding area. * Production data compiled by Manitok from: Geoscout and public databases. 16
Balanced Corporate Risk/Reward Adding Entice as a Second Core Area Reduces Risk Profile and Increases Exposure to Oil Achieving a corporate production level greater than 10,000 boe/d in the next 2 years, along with a large transparent drilling inventory would improve MEI s market valuation; 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 pattern); 3 year primary term plus an option to extend for an additional 3 years under the same terms; 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 (same scale as AB Crown Royalties); Priority 2 processing status in Encana facilities with estimated spare capacity of 15 MMcf/d; extensive Encana pipeline system through land base; Multi-zone Potential, Proprietary 3D Seismic Data and Public Log Data on ~250 Wellbores +200 million bbls of offsetting historical oil production and over 50 successful horizontal wells drilled in the Lithic Glauconitic and Basal Quartz (Ellerslie) by Cenovus on offsetting lands; Leased lands include full 3D seismic coverage (~420 sq. miles) with an estimated replacement value of greater than $40 million; Primary targets include the Glauconitic and Basal Quartz (Ellerslie); secondary targets include Viking, Upper Mannville, Pekisko and Nisku; Prairie Sky Royalty Ltd. to be Spun Out of Encana in 2014 Royalty Corp s success is important to Encana s future corporate strategy; both Prairie Sky Royalty Ltd. and Encana consider partnership with MEI as important to its start-up strategy. 17
Initial Entice Drilling Locations Horizontal and Vertical Locations to Date: 2 vertical Nisku 10 12 potential vertical follow up locations 3 vertical Glauc 12 16 potential vertical follow up locations 6 horizontal Lithic Glauc 22 28 potential Hz follow up locations 6 horizontal Basal Quartz (Ellerslie) 24 32 potential Hz follow up locations 5 horizontal Basal Quartz (Ellerslie) 20 28 potential Hz follow up locations Twp 28 Twp 25 R25 R23 Each township is 36 square miles; 9 townships is 324 square miles 5 wells drilled to date; the 5 will be completed in Q2 2014; Drilling begins again in Entice as soon as breakup is over (approximately late June 2014); Planning an additional 10 to 12 horizontal wells and possibly 1 to 3 vertical wells over the remainder of 2014. Twp 22 Mannville well density shown on map 18
Basal Quartz (Ellerslie) Prospects 14 bypassed pay opportunities identified to date ( ) ; Modeled 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 Horizontal well economic parameters: - Drill, Case, E&T $2.9 million - IP30 205 boe/d (80% oil) - EUR 230 Mboe (1) - NPV10 $3.1 million - IRR 75% T26 T2 5 T23 T22 Basal Quartz (Ellerslie) Wells are RED Lower Mannville produced ~15 MMbbls since 1979. Drilling of Basal Quartz (Ellerslie) 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. Basal Quartz (Ellerslie) Entice B Pool Produced 5 MMBO 39 Wells (only 1 Hz well) 1987 1) Estimates internally generated by Manitok Management using data from GeoScout and the AER. 19
Multi-Stage Fracs - Key to Unlocking Variability of Reservoir Quality Cenovus Operated Wells - Wayne & Drum Basal Quartz (Ellerslie) GG Pool Basal Quartz (Ellerslie) horizontal wells have had significant success despite offsetting some very low rate vertical wells (1) ; Nine recent Cenovus Hz wells, directly offsetting the original ultra low rate vertical wells, exhibiting stabilized initial production (IP) rates ranging from ~80 to ~400 bopd; CVE 102/13-15-27-18W4 Horizontal Well RR 2011 BQ (ELRL) Cum: 113,667 BO CP: 116bopd, IP: 530 bopd T27 CVE 103/6-10-27-18W4/02 Vertical, deviated well RR 2009 BQ (ELRL) Cum: 3,849 BO CP: 2.7 bopd CVE 100/11-15-27-18W4 Vertical, deviated well RR 2009 BQ (ELRL) Cum: 8,163 BO CP: 3.5 bopd, IP: 18 bopd CVE 100/16-15-27-8W4 Horizontal Well RR 2011 BQ (ELRL) Cum: 102,498 BO CP: 83bopd IP: 417 bopd CVE 3 Horizontal Wells Sections 10 & 11 RR 2011-2012 BQ (ELRL) Cum: ~200,000 BO CP: 430 bopd, IP: 1,111 bopd CVE 4 Horizontal Wells Section 27 RR 2012-2013 BQ (ELRL) Cum: ~121,000 BO CP: 1,032 bopd, IP:1,083 bopd Combined initial production (IP) rates of over 3,000 boe/d and combined current production (CP) of ~1,660 boe/d from 9 Hz wells; CVE 100/13-22-26-18W4 Vertical Well RR 2006 BQ (ELRL) Cum: 2,174 BO CP: Susp at <2 bopd R18W4 1) Data compiled by Manitok from: Geoscout, Canadian Discovery. Manitok has no working interest in these wells. 20
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 Hz Frac Results in Basal Quartz (Ellerslie) Reservoir IP90 Rates Cenovus Hz Drills 2010-2013 Wayne-Rosedale BQ (Ellerslie) (1) 800.0 700.0 600.0 2010 2011 2012 2013 NCS Multistage (uncemented, Hybrid ) NCS Multistage (cemented) PP StackFRAC No Record 500.0 IP90 (BOE/d) 400.0 300.0 200.0 100.0 0.0 1) Data compiled by Manitok from: Geoscout, Canadian Discovery 21
Horizontal Wells vs. Offset Vertical Wells in the Basal Quartz (Ellerslie) 700.0 600.0 500.0 400.0 300.0 Cenovus Wayne-Rosedale - Horizontal BQ vs. Vertical BQ Offset Wells - 120 day Initial Production rates (boe/d) There is not a correlation between vertical and horizontal well IP rates, which suggests that there is variability in the quality of the reservoir. That is best exploited with horizontal drilling and multi-stage fracing which gives you a much higher probability of intersecting a greater amount of higher quality reservoir within each wellbore than with vertical wells alone. 200.0 100.0 0.0 Offset Vertical Well Production HZ Well Production 22
Glauconitic Channel Prospects 11 bypassed log leads initially identified ( ); Glauconitic Wells are GREEN Channel prospects being validated by 3D seismic interpretation and reservoir rock analysis; Mostly Lithic Glauc, with some potential quartzose glauc opportunities; Lithic Glauc Horizontal well economics: - Drill, Case, E&T $2.7 million - IP30 200 boe/d - EUR 220 Mboe (1) - NPV10 $2.9 million - IRR 76% Seismic Interpretation of Glauc Channel Trends in T28-25W4 Rockyford U Mann F Pool Produced 6 MMbbls 20 wells since 1987 Glcc A Pool Produced 1.2 MMbbls 9 Wells since 1992 1) Estimates internally generated by Manitok Management using data from GeoScout and the AER. 23
Hz Frac Results in Lithic Glauconitic Reservoir IP90 Rates Cenovus Hz Drills 2010-2013 Bantry/Cessford Glauconitic (1) 600.0 500.0 2010 2011 2012 2013 NCS Multistage (uncemented, Hybrid ) NCS Multistage (cemented) PP StackFRAC No Record IP90 (BOE/d) 400.0 300.0 200.0 100.0 0.0 1) Data compiled by Manitok from: Geoscout, Canadian Discovery 24
Why Buy Manitok Shares? Bargain basement valuation at less than 2.5x forecast 2014 cash flow and at 60% of 2P NAV; Manitok s strong growth profile in the foothills will continue through the exploitation of its large undeveloped land base and the leveraging of its expertise at a time when there is little competition; The addition of the Entice land provides potential for scale, increased oil production and greater visibility of its drilling inventory by the fourth quarter of 2014 and through the next 5 years; Pristine balance sheet will allow Manitok to fund its 2014 capital expenditure program from cash flow and its existing credit facility; likely to be the same in 2015; Long term corporate plan to become a dominant exploitation / exploration group in both the Foothills and SE Alberta over the next 5 years; targeting 20,000 boe/d in 5 years. 25
Appendix 26
IP 120 (x) Horizontal Productivity Multiple vs. Offset Vertical Wells in the Basal Quartz (Ellerslie) 30 25 Cenovus Wayne Rosedale Basal Quartz Productivity Multiplier Horizontal vs. Vertical Offset Well 20 15 10 5 0 Well I.D. 27
Entice Quartzose Glauconitic Analog Many identified log leads resemble Edge Well similar to the 12-22 well ( 1 on the cross section) 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 only 400m wide; Excellent reservoir with 20% porosity, 200 to 500md permeability, 25% Sw, oil gravity of 28-35 API; 1 2 Vertical well economics: - Drill, Case, E&T $1.0 million - IP30 50 boe/d - EUR 55 Mboe (1) - NPV10 $1.0 million - IRR 60% Cross Section Illustrating Thickening of Reservoir From the Well 1 Edge Well to the Centre of the Rockyford Pool Well 2 12-22 14-22 Thin Channel Lag at Edge Thick Channel Sand in Centre Majority of Identified Bypass Pay Wells are Thin Channel Lag Deposits (Edge Wells) 28
1,000m Stolberg Cross Section Cordel structure Main Stolberg structure Additional untested structures Structural cross section through T42-15W5 showing both the Cordel and Stolberg Cardium pools along with several untested structures. 29
Hedging at May 1, 2014 Subject of Notional Average Contract Contract Quantity Remaining Term Reference Strike Price Traded Oil 500 bbls/d January 1, 2014 to December 31, 2014 CAD$ WTI $96.00 Swap Oil 500 bbls/d January 1, 2014 to December 31, 2014 CAD$ WTI $93.35 Swap Oil 300 bbls/d January 1, 2014 to December 31, 2014 CAD$ WTI $94.00 Swap Oil 500 bbls/d June 1, 2014 to December 31, 2014 CAD$ WTI $105.17 Swap Oil 1,000 bbls/d June 1, 2014 to December 31, 2014 Ed. Sweet basis (CAD$) $8.67 Oil 1,000 bbls/d January 1, 2015 to December 31, 2015 CAD$ WTI $95.00 Swap Oil 500 bbls/d January 1, 2015 to December 31, 2015 CAD$ WTI $91.00 Swap Natural gas 5,000 GJs/d January1, 2014 to December 31, 2014 CAD$ AECO $3.350 Put (1) Natural gas 5,000 GJs/d January1, 2014 to December 31, 2014 CAD$ AECO $3.750 Put (1) Natural gas 5,000 GJs/d January1, 2015 to December 31, 2015 CAD$ AECO $3.730 Put (2) Natural gas 2,000 GJs/d April 1, 2014 to October 31, 2014 CAD$ $3.660 Forward Sale Natural gas 2,000 GJs/d April 1, 2014 to October 31, 2014 CAD$ $3.760 Forward Sale Natural gas 2,000 GJs/d April 1, 2014 to October 31, 2014 CAD$ $3.875 Forward Sale Oil 500 bbls/d January 1, 2015 to December 31, 2015 CAD$ WTI $96.00 Swaption (3) Oil 1,000 bbls/d January 1, 2016 to December 31, 2016 CAD$ WTI $95.00 Swaption (4) Oil 500 bbls/d January 1, 2016 to December 31, 2016 CAD$ WTI $91.00 Swaption (5) (1) The counter-party to this contract receives a deferred put option premium of $0.35/GJ. (2) The counter-party to this contract receives a deferred put option premium of $0.33/GJ. (3) The counter-party to this contract holds a one-time option no later than December 31, 2014 to extend a swap on 500 barrels per day of oil at CAD$96.00 for the period indicated. (4) The counter-party to this contract holds a one-time option no later than December 31, 2015 to extend a swap on 1,000 barrels per day of oil at CAD$95.00 for the period indicated. (5) The counter-party to this contract holds a one-time option no later than December 31, 2015 to extend a swap on 500 barrels per day of oil at CAD$91.00 for the period indicated. 30
Price Deck SPROULE APRIL 1, 2014 1 WTI Cushing Oklahoma $US/Bbl Edmonton Par Price 40 API $/Bbl Synthetic Crude Oil Edmonton 34 API $/Bbl Cromer LSB 35 API $/Bbl - Prices in Canadian Dollars - Hardisty Heavy 12 API $/Bbl Western Canada Select (WCS) 20.5 API $/Bbl Hardisty Bow River 24.9 API $/Bbl Cold Lake Blend 22.6 API $/Bbl 2 Energy Cost Inflation Rate %/Yr Cost Inflation Rate %/Yr Year 2014 4 mo. Act 99.52 101.06 110.99 98.60 77.99 87.18 84.76 82.00 25.3% 0.0 0.907 2014 8 mo. Est 98.72 100.91 108.41 98.91 76.69 84.76 85.77 83.75 24.3% 1.5 0.900 2015 90.94 95.99 103.49 93.99 72.95 80.63 81.59 79.67-8.3% 1.5 0.900 2016 85.51 95.01 102.51 93.01 72.21 79.81 80.76 78.86-6.0% 1.5 0.900 2017 90.54 100.60 108.10 98.60 76.46 84.51 85.51 83.50 5.9% 1.5 0.900 2018 95.52 106.14 113.64 104.14 80.66 89.15 90.22 88.09 5.5% 1.5 0.900 2019 96.96 107.73 115.23 105.73 81.87 90.49 91.57 89.41 1.5% 1.5 0.900 2020 98.41 109.34 116.84 107.34 83.10 91.85 92.94 90.76 1.5% 1.5 0.900 2021 99.89 110.98 118.48 108.98 84.35 93.23 94.34 92.12 1.5% 1.5 0.900 2022 101.38 112.65 120.15 110.65 85.61 94.63 95.75 93.50 1.5% 1.5 0.900 2023 102.91 114.34 121.84 112.34 86.90 96.04 97.19 94.90 1.5% 1.5 0.900 2024 104.45 116.05 123.55 114.05 88.20 97.49 98.65 96.32 1.5% 1.5 0.900 2025 106.02 117.79 125.29 115.79 89.52 98.95 100.13 97.77 1.5% 1.5 0.900 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 - Prices in Canadian Dollars - Dawn $/MMbtu Ethane Plant Gate $/Bbl Edmonton Propane $/Bbl Edmonton Butane $/Bbl Edmonton Pentanes Plus $/Bbl 2014 4 mo. Act 4.71 5.41 10.25 5.25 5.73 11.07 15.00 71.26 72.92 113.30 28.79 2014 8 mo. Est 4.63 4.77 4.34 4.72 5.22 5.44 13.22 59.85 75.21 112.74 75.00 2015 4.32 4.43 4.00 4.38 4.88 5.10 12.28 47.44 71.54 107.24 76.13 2016 4.22 4.32 3.89 4.27 4.77 4.99 11.97 46.96 70.82 106.15 77.27 2017 4.78 4.93 4.51 4.88 5.38 5.61 13.67 49.72 74.98 112.40 78.43 2018 5.04 5.23 4.80 5.18 5.68 5.90 14.49 52.46 79.11 118.58 79.60 2019 5.12 5.31 4.89 5.26 5.76 5.99 14.73 53.24 80.29 120.36 80.80 2020 5.19 5.40 4.97 5.35 5.85 6.07 14.96 54.04 81.50 122.16 82.01 2021 5.27 5.49 5.06 5.44 5.94 6.16 15.20 54.85 82.72 124.00 83.24 2022 5.35 5.57 5.15 5.52 6.02 6.25 15.45 55.67 83.96 125.86 84.49 2023 5.43 5.66 5.23 5.61 6.11 6.33 15.69 56.51 85.22 127.74 85.75 2024 5.51 5.75 5.33 5.70 6.20 6.43 15.94 57.36 86.50 129.66 87.04 2025 5.60 5.85 5.42 5.80 6.30 6.52 16.20 58.22 87.80 131.61 88.35 Escalation Rate of 1.5% Thereafter Exchange Rate $US/$Cdn Plant Gate Sulphur $/LT 31
Analyst Coverage Acumen Capital Trevor Reynolds Canaccord Genuity Anthony Petrucci Clarus Securities Inc. Daniel Choi Dundee Capital Markets Chad Ellison GMP Securities Aaron Swanson Integral Capital Markets Rob Knowles Macquarie Capital Markets Canada Ltd. Ray Kwan National Bank Financial Dan Payne RBC Capital Markets - Shailender Randhawa TD Securities Inc. Juan Jarrah 32
List of Comparison Companies in Slides 9 and 10 AEI - Arsenal Energy Inc. ARN - Arcan Resources Ltd. BNE - Bonterra Energy Corp. CJ - Cardinal Energy Ltd. CKE - Chinook Energy Inc. CR - Crew Energy Inc. DTX - Deethree Exploration Ltd. GXE - Gear Energy Ltd. HYX - Hyperion Exploration Corp. LEG - Legacy Oil + Gas Inc. LNV - Longview Oil Corp. LRE - Long Run Exploration Ltd. MEI - Manitok Energy Inc. MQL - Marquee Energy Ltd. OIL - LGX Oil + Gas, Inc. PRY - Pinecrest Energy Inc. PXL - Palliser Oil & Gas Corporation RE - Rock Energy Inc. RMP - RMP Energy Inc. RRX - Raging River Exploration Inc. SGY - Surge Energy Inc. SOG - Strategic Oil & Gas Ltd. SPE - Spartan Energy Corp. TBE - Twin Butte Energy Ltd. TOG - TORC Oil & Gas Ltd. TVE - Tamarack Valley Energy Ltd. YGR - Yangarra Resources Ltd. ZAR - Zargon Oil & Gas Ltd. 33