Future Drilling Locations. Well Test Results

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2 Certain information with respect to Ikkuma Resources ( IKM or the Corporation ) included in this presentation constitutes forward-looking information under applicable securities legislation. Forward-looking information typically contains statements with words such as anticipate, believe, expect, plan, intend, estimate, propose, project or similar words suggesting future outcomes or statements regarding an outlook. Forward-looking information in this presentation may include, but is not limited to, potential flow rates from recently completed wells, the number of de-risked, low risk drilling locations, the number of offset locations, the timing of future drilling operations, the potential future OPEX in the $ $4.50 range, expected future well flow rates, the type and timing of capital expenditures. the estimated replacement value of facilities, plants and pipelines, initial production rates could be as high as 200 to 1,300 boe/d, expectations relating to Foothills fractured fairways, condensate trading at a $3.00 to $10.00 per barrel premium to Edmonton light crude, the estimated 30 well, three year Foothills light oil pool drilling program with a projected $ MM CAPEX requirement and the annualized cash flow and peak production amounts applicable thereto, more effectively managing future trunk line volumes, the addition of strong PDP bookings from new wells, the higher likelihood of undeveloped reserves being converted to producing reserves in the near term, the Corporation s future operations contemplated for the remainder of 2017 and the expectation that oil recoveries by Ikkuma will be higher than other deep basin reservoirs. Forward-looking information is based on a number of factors and assumptions which have been used to develop such information but which may prove to be incorrect. Although management believes that the expectations reflected in its forward-looking information are reasonable, undue reliance should not be placed on forwardlooking information because there can be no assurance that such expectations will prove to be correct. In addition to other factors and assumptions which may be identified in this presentation, assumptions have been made regarding and are implicit in, among other things, expectations and assumptions concerning the performance of existing wells and success obtained in drilling new wells, anticipated expenses, cash flow and capital expenditures and the application of regulatory and royalty regimes. Readers are cautioned that the foregoing list is not exhaustive of all factors and assumptions which have been used. Since forward-looking statements address future events and conditions, by their very nature they involve inherent risks and uncertainties. Actual results could differ materially from those currently anticipated due to a number of factors and risks. These include, but are not limited to, risks associated with the oil and gas industry in general (e.g., operational risks in development, exploration and production; delays or changes in plans with respect to exploration or development projects or capital expenditures; the uncertainty of reserve and resource estimates; the uncertainty of estimates and projections relating to production, costs and expenses, and health, safety and environmental risks), commodity price and exchange rate fluctuations and uncertainties resulting from potential delays or changes in plans with respect to exploration or development projects or capital expenditures. The recovery and reserve and resource estimates contained in this Corporate Presentation are estimates only and there is no guarantee that the estimated reserves and resources will be recovered.. Forward-looking information is based on current expectations, estimates and projections that involve a number of risks and uncertainties which could cause actual results to differ materially from those anticipated by the proposed management and described in the forward-looking information. The forward-looking information contained in this presentation is made as of the date hereof and management undertakes no obligation to update publicly or revise any forward-looking information, whether as a result of new information, future events or otherwise, unless required by applicable securities laws. The forward-looking information contained in this presentation is expressly qualified by this cautionary statement. This presentation contains the term netbacks which is not a term recognized under IFRS. This measure is used by management to help evaluate corporate performance as well as to evaluate acquisitions. Management considers netbacks as a key measure as it demonstrates its profitability relative to current commodity prices. Operating net backs are calculated by taking total revenues (net of realized hedging gains or losses) and subtracting royalties, operating expenses and transportations costs on a per BOE basis. BOE Disclosure The term barrels of oil equivalent ( BOE ) may be misleading, particularly if used in isolation. A BOE conversion ratio of six thousand cubic feet per barrel (6Mcf/bbl) of natural gas to barrels of oil equivalence is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead. All BOE conversions in the report are derived from converting gas to oil in the ratio mix of six thousand cubic feet of gas to one barrel of oil, which may be misleading as an indicator of value given that the values are based on the current price of crude oil and natural gas is significantly different from the energy equivalency of 6:1. In this presentation: (i) mcf means thousand cubic feet; (ii) mcf/d means thousand cubic feet per day (iii) mmcf means million cubic feet; (iv) mmcf/d means million cubic feet per day; (v) bbls means barrels; (vi) mbbls means thousand barrels; (vii) mmbbls means million barrels; (viii) bbls/d means barrelsper day; (ix) bcf means billion cubic feet; (x) mboe meansthousandbarrelsof oil equivalent; (xi) mmboe meansmillion barrelsof oil equivalentand (xii) boe/d meansbarrelsof oil equivalentperday. 2

3 Future Drilling Locations Unless otherwise specified, the information in this Corporate Presentation pertaining to future drilling locations or drilling inventories is based solely on internal estimates made by management and such locations have not been reflected in any independent reserve or resource evaluations prepared pursuant to NI , other than the Resource Report (as hereafter defined). Similarly, unless otherwise specified, the information in this Corporation Presentation pertaining to targeted reserve volumes from future drilling is intended to indicate that in making its internal drilling decisions, the Corporation seeks to target drilling locations that, based on previous drilling results and its own internal assessments, it believes will on average ultimately generate the indicated volumes. This Corporate Presentation discloses drilling locations which are unbooked locations and are internal estimates based on the Corporation s prospective acreage and an assumption as to the number of wells that can be drilled per section based on industry practice and internal review. Except as set out in the Resource Report, unbooked locations do not have attributed reserves or resources and have been identified by management as an estimation of multi-year drilling activities based on evaluation of applicable geologic, seismic, engineering, production and reserves information. There is no certainty that Ikkuma will drill all unbooked drilling locations and if drilled there is no certainty that such locations will result in additional oil and gas reserves, resources or production. The drilling locations on which the Corporation actually drills wells will ultimately depend upon the availability of capital, regulatory approvals, oil and natural gas prices, costs, actual drilling results, additional reservoir information that is obtained and other factors. While certain of the unbooked drilling locations have been de-risked by drilling existing wells in relative close proximity to such unbooked drilling locations, other unbooked drilling locations are farther away from existing wells where management has less information about the characteristics of the reservoir and therefore there is more uncertainty whether wells will be drilled in such locations and if drilled there is more uncertainty that such wells will result in additional oil and gas reserves, resources or production. Of the 52 development locations shown on p.17, six are proved plus probable locations identified in the 2016YE Sproule Report. Well Test Results Certain well test results disclosed in this Corporate Presentation represent short-term results, which may not necessarily be indicative of long-term well performance or ultimate hydrocarbon recovery therefrom. Full pressure transient and well test interpretation analyses have not been completed and as such the flow test results contained in this Corporate Presentation should be considered preliminary until such analyses have been completed. 3

4 Presentation of Oil and Gas Resources Estimates of future net revenue, whether calculated without discount or using a discount rate, do not represent fair market value. With respect to the discovered resources (including contingent resources) disclosed in this Corporate Presentation, there is uncertainty that it will be commercially viable to produce any portion of the resources. With respect to the undiscovered resources (including prospective resources) disclosed in this Corporate Presentation, there is no certainty that any portion of the resources will be discovered. If discovered, there is no certainty that it will be commercially viable to produce any portion of the resources. Certain resource estimate volumes disclosed herein are arithmetic sums of multiple estimates of contingent or prospective resources and reserves, which statistical principles indicate may be misleading as to volumes that may actually be recovered. Readers should give attention to the estimates of individual classes of resources or reserves and appreciate the differing probabilities of recovery associated with each class as explained below or in Ikkuma s Annual Information Form for the year ended December 31, Resources and Production Resources encompass all petroleum quantities that originally existed on or within the earth s crust in naturally occurring accumulations, including discovered and undiscovered (recoverable and unrecoverable) plus quantities already produced. Resources are classified as follows: Total PIIP is that quantity of petroleum that is estimated to exist originally in naturally occurring accumulations. It includes that quantity of petroleum that is estimated, as of a given date, to be contained in known accumulations, prior to production, plus those estimated quantities in accumulations yet to be discovered. Total resources is equivalentto total PIIP. Discovered PIIP is that quantity of petroleum that is estimated, as of a given date, to be contained in known accumulations prior to production. The recoverable portion of discovered PIIP includes production, reservesand contingent resources; the remainder is unrecoverable. Contingent resources are those quantities of petroleum estimated, as of a given date, to be potentially recoverable from known accumulations using established technology or technology under development, but which are not currently considered to be commercially recoverable due to one or more contingencies. Undiscovered PIIP is that quantity of petroleum that is estimated, on a given date, to be contained in accumulations yet to be discovered. The recoverable portion of undiscovered PIIP is referred to as prospective resources; the remainder is unrecoverable. 4

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6 Sprott, May 2017 Energy sector has never fallen for 6 sequential months worst performing sector in the world... The market is stuck in a negative feedback loop as largely ignorant headlines (legitimately fake news ) about persistent US supply growth, the impotence of the OPEC production cut, and weak demand bombard investors day after day on CNBC, BNN, and other mainstream media 40-50% YTD portfolio destruction for select PMs. oil fundamentals are generally quite good. OPEC is largely out of spare capacity on a pre-cut basis. Non-US/OPEC growth is challenged in the years ahead given the largest drop in spending on long-lead projects in the history of the oil and gas business. 6

7 Arc Energy Charts, June 2017 Shale oil will be challenged to meet the future production gap, particularly in light of the recent surge in US energy service costs. Economists, May

8 Base power demand continues to increase along with US Exports. Weather is always an important variable for demand; Recently, heating/cooling demand has been average, but 8

9 TD June, 2017 Strip is challenged, BUT weekly injection is largely below the 5 year average, supply has flattened, and base (power/export) demand has picked up. Weather: ENSO Neutral (in other words: don t know what the future will bring!!) As Pel nino increases, price may collapse as traders follow a bearish forecast. NOAA, May

10 Uitca/Marcellus Takeaway (Bloomberg Feb, 2017) TD June, 2017 Storage is above the 5 year trend in the US and Canada. Pent-up supply with infrastructure buildout. Supply has flattened, though associated gas expected to increase. TD June, 2017 Some suggest an oversupply in NE USA gas infrastructure. 10

11 Some hope GMP First Energy May, 2017 GMP First Energy May, 2017 Rising WCSB supplies having hungry home in local markets. U.S. export market requires Canada gas at least in near future. Upside on basis (price spread) and Canadian supplies will have substantial near-term demand. 11

12 Focus Symbol Shares Outstanding: Basic / Diluted Market Capitalization: Basic / Diluted (1) Alberta & BC Foothills: Low decline; Gas weighted base production; Light oil upside TSX-V: IKM 94.2 MM / MM $66 MM / $73.6 MM Insider Ownership: Basic / Diluted (4) 16% / 20% Current Production Current Outstanding Debt (2) Available Credit Facilities 6,500-6,900 boe/d (98% gas-weighted) $35 MM $25 MM 2017 Capital Program $20-29 MM (~ $10 MM spent to date) Reserves (1P/ 2P) (3) Contingent Plus Prospective Resources (5) Current Net Undeveloped / Net Developed Land Infrastructure Tax Pools 19.9 MMboe / 27.5 MMboe MMboe WI (98% oil) 159,917 / 63,947 acres 560 km Pipelines; 9 Processing facilities; and Ownership in 3 gas plants $207 MM (1) Based on $0.70/share. (2) $45 million AIMCo second lien facility less cash deposits. (3) Reserves evaluation from the 2016YE Sproule Report. (4) Includes Royal Capital Management Corp. (5) Resource evaluation from the May 31, 2017 Deloitte LLP Resource Report as more particularly described in Ikkuma s June 5 th Press Release. 12

13 Proven Team Technical team with 150+ years of combined foothills operational experience. Successfully mitigated low commodity prices in 2016 with hedging; 4,265 boe/d of 2017 gas production is hedged at $2.86/Mcf (AECO). Top quartile cost efficiencies amongst a select list of Canadian producers. Low Decline Core Asset 10-18% annual decline. Core asset OPEX is approximately $8/boe and future reductions are anticipated. Sweet gas redirect potential within existing infrastructure will further decrease OPEX. Growth Potential 89% WI in an emerging foothills Cardium light oil play with a potential drilling inventory of 150+ locations. Estimated million barrels gross ( million Barrels, WI) PIIP (1) on Ikkuma s land base (P50 volume estimate). Cardium oil provides multiyear inventory of light sweet oil drilling, within a pool which ranks as one of the largest discovered conventional oil pools in Western Canada in the last 3 decades. (2) Over 50 gas drilling locations planned, when gas prices support drilling. Underutilized, extensive midstream assets poised for future growth. (1) PIIP Petroleum Initially In Place; additional information is available in the Appendix herein and in Ikkuma s June 5th, 2017 press release. (2) Data and conclusion is based on (public) Geoscout OOIP (original oil in place) data, and is shown graphically later in the presentation. 13

14 Low decline, stacked reservoirs (Wilrich, Falher, Cadomin, Cadotte, Dunvegan, Cardium), containing oil and gas. Identified multiyear drilling inventory for gas and potentially large (bypassed) oil pools. Team was involved previously in building the asset; 9 facilities, including 3 gas plants, ~560 km pipelines. (2) Highly focused with numerous undeveloped stacked conventional structured reservoirs. 12% 32% 7% 11% 2% Area production, as a percent of total (1) 20% IKM Trunk Pipeline (1) (2) Approximately 16% of total production is in southern Alberta Foothills. Estimated replacement value of $ MM. 14

15 Cardium Oil and Gas Pools > 4,500 producing Cardium HZ wells in western Canada. Narraway Many juniors are exploiting Cardium pools in the deep basin, including: Torc (Kaybob, Rosevear, Carrot); Vermillion, Bellatrix, Bonterra, Arc in Pembina; Bonavista, Yangarra, Taqa, Tourmaline (Williston Green and nearby areas); Petrus, Bellatrix, Bonavista (Ferrier); Pengrowth, Whitecap, Exxon (Harme); Orlen (Lochend). Cardium is the largest conventional onshore oil pool in western Canada. 15

16 Approximate Oil Pool Outline Discovery Well #1, 1999 (vertical well), IP 220 bbl/d, 31Mbbl Average 89% WI in 44 sections of land. Regional hydrocarbon charge and extensive, well developed fracture network in a conventional reservoir with porosities up to 12%. Q1, Q2 Drilling Operations Two New Oil Pool Discoveries: W6 and W locations have been identified so far. Based on regional analysis and other Cardium foothills analogues, initial rates could be as high as 200 1,300 boe/d. Reservoir quality and occurrence of condensate appears comparable to other foothills oil reservoirs. Condensate can trade at a $3- $10/Bbl premium to Edmonton Light. 16

17 Large pool with two play types: deep basin resource play and foothills fractured conventional play. Reservoir quality as good, or better than, many deep basin Cardium plays. Cardium is characterized by 15-18m of clean sandstone with porosities up to 12%. Reservoir is above bubble point. Deep Basin Resource Play Scalable, repeatable oil program with focus on D&C optimization for improving economics. Apply deep-basin operator learnings to optimize stimulation and lateral lengths to maximize IP30. Deep basin locations characterized by longer laterals and multi-stage fracture stimulations. Natural fractures are anticipated in deep basin areas, but less common than in faulted areas. Foothills Fractured Conventional Play High permeability sweet spots anticipated in many of the 150+ locations identified to date. Geosteering to remain in porous, fractured intervals is fundamental for increased production. Highly fractured foothills locations may or may not require fracture stimulations. Economics anticipated to be better in fractured fairways. 17

18 EUR (BBL) 300, , , , ,000 50,000 - Deep Basin Oil Pools Foothills Oil Pools EUR vs PhiH Cordel Stolberg Lochend NW Pembina E Pembina N Pembina Rosevear Ferrier Kaybob Wapiti Wilson Ck Med River Berland Pine Creek Fir Harme Notin-Carrot Will Grn Kakwa Edson Narraway PhiH Deep basin pools consistently display lesser reservoir PhiH. Foothills Pools (Cordel and Stolberg) have the added benefit of natural fractures, resulting in increased reservoir capability. Narraway (PhiH) reservoir quality is excellent compared to most producing fields. PhiH (1) Pools are heterogeneous. Representative logs were selected in order to determine porosity and reservoir thickness. Cardium reservoir variability is assumed ubiquitous. (2) Cardium gas wells are excluded from the analysis. 18

19 Gross in place oil on Ikkuma lands: pools size ranks 28 th in size of largest pools ever discovered in western Canada. One of the two largest discoveries in BC and Alberta for the last ~36 years, and the largest in Alberta for that time period. Alberta and BC Field OOIP vs Discovery Date 10, Narraway (gross PIIP, Cardium)* 1, OOIP (MMBO) Discovery Date Alberta and BC Fields IKM Narraway Expon. (Alberta and BC Fields) * Gross Petroleum initially in Place (PIIP) volume for the Cardium only, as described in the Resource Report. The Narraway pool extends beyond the lands owned by Ikkuma, but these areas were not evaluated in the Resource Report. Vertical discovery well was drilled in 1999, but recent HZ delineation and recompletions by Ikkuma defines the pool size. Source: Geoscout 19

20 150+ possible well locations Two potential development scenarios considered 42 wells over 4 years, 1 rig 2019/2020: Projected $157 MM CAPEX (2,4) Peak production 4,103 boe/d (2) Peak annualized cash flow of $65 MM/yr (3) Self sustaining program by early-mid 2020 D/CF at model end: 0.6X 50 wells over 4 years, 2 rigs 2019/2020: Projected $185 MM CAPEX requirement (2,4) Peak production 5,858 boe/d Peak annualized cash flow of $86 MM/yr (3) Self sustaining program by early-mid 2020 D/CF at model end: 1.7X IP BOE/d Single Well IRR vs IP (MRF) (3) IP (bbl/d) 0 0% 50% 100% 150% 200% IRR (%) (1) Narraway Resource Report, released June 5 th, 2017, indicates 485 MMBoe WI PIIP (2) IP 250 boe/d, $ MM/well (3) Pricing: 2017 $60.00 C$/bbl and $3.00 C$/MMBTU, inflated 3% annually (4) Capital and operating cost per well reduced with time due to operational efficiencies 20

21 In the southern part of IKM s asset base, there is at least 120 MMcf/d gas processing and transporting capability that could bring OPEX to $4.25-$4.50/boe, thus becoming one of the lowest cost producers in the basin. Potentially lower OPEX and low decline conventional reservoirs provides long term value in a volatile commodity environment. 560 km of operated pipelines gives Ikkuma several options to deliver gas to multiple processing points. Ownership in 3 gas plants and optionality in at least 3 additional, underutilized gas processing facilities. With increasing production, trunk line volumes may be managed more effectively. Elmworth Narraway (7% WI) Unused capacity ~100 MMcf/d Edson Horse Copton (70% WI) Leland (39% WI) Unused capacity ~120 MMcf/d IKM Pipeline 21

22 IKM Source: Beacon Securities Report, Q

23 Exceptionally low corporate decline drives best-in-class growth capital efficiencies. Late-life production and strong conventional reserve bookings. New wells add to strong PDP bookings. IKM Source: Averaged interpreted base declines (BMO, May, 2017) 23

24 Why own IKM stock? 1. Unique business model matched with the right team Experienced technical team with highly specialized engineering and geoscience skills. Underexploited part of the basin: prolific conventional reservoirs proven to exist in bypass zones, based on Ikkuma s recompletion results to date. One of the largest light oil pool discoveries in the last 30 years in the basin highlights the underexploited nature of the foothills. Significant undeveloped land position with few barriers for acquiring new land; since 2014, IKM has grown its undeveloped land base by 157% to 167,000 net undeveloped acres. 2. Solid base production Low cost producer. Low corporate decline, generates exceptional production growth capital efficiency. Natural gas production well hedged through Leading G&A efficiencies. 3. Clear path to growth Significant light oil pool discovery: 485 MMBoe WI PIPP (1) Multiyear drilling inventory (oil and gas) that has been de-risked with current recompletion operations. (1) For complete disclosure of PIIP (petroleum initially in place), see June 5th press release. 24

25 MANAGEMENT Tim de Freitas President & CEO Dorothy Else Executive VP Carrie Yuill VP Finance & CFO Yvonne McLeod Senior VP Engineering Greg Feltham VP Exploration Rich Rowe VP Land BOARD OF DIRECTORS Robert Dales (Chairman) Dave Anderson Tim de Freitas Charle Gamba William Guinan (Corporate Secretary) Mike Kohut ANALYST COVERAGE Acumen Capital Trevor Reynolds Beacon Securities Kirk Wilson Clarus Securities Rob Pare Desjardins Jamie Kubik First Energy Cody Kwong Haywood Securities Darrell Bishop PI Financial Brian Purdy TD Securities Juan Jarrah BANKS The Toronto-Dominion Bank ATB AUDITOR KPMG LLP LEGAL COUNSEL Borden Ladner Gervais LLP TRANSFER AGENT Alliance Trust Company RESERVE EVALUATORS Sproule and Associates Ltd. CORPORATE OFFICE Suite 2700, th Avenue SW Calgary, AB T2P 3H5 T: (403)

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27 Opportunities Identified to Date 52 gas development locations (>45 Mboe/d net potential).(1) recompletions (>5 Mboe/d net potential).(1) 29 Locations : North (5 Dunvegan, 2 Cadotte, 14 Falher, 8 Nik) 13 Locations : Central (4 Dunvegan, 1 Cadotte, 6 Falher, 2 Nik) Recompletions within Core Asset Base (incl. Cardium, Dunvegan, Cadotte, Falher, Gething, Nik) 10 Locations : South (5 Dunvegan, 3 Falher, 2 Nik) (1) Of the 52 gas locations identified, 6 locations are booked as proven + probable. 27

28 Reserves Category NPV 10% (M$) Oil (Mbbl) Liquids (Mbbl) Gas (MMcf) MBOE Developed Producing $ 103, ,501 13,642.2 Developed Non-Producing $ 14, ,354 2,238.4 Undeveloped $ 13, ,384 4,050.3 Total Proved $ 131, ,239 19,930.9 Probable $ 58, ,798 7,607.6 Total proved plus probable $ 190, ,037 27,538.5 Based on Dec 2016 Consensus Price Forecast (Sproule, McDaniel, GLJ) NET ASSET VALUE PER SHARE 10% NPV of 2P P&NG reserves, before tax ($000's) $ 190,031 Undeveloped land (1) ($000's) $ 20, YE Net Debt (Unaudited) ($000's) $ (32,465) Net asset value ($000's) $ 178,416 Common shares outstanding (000's) - basic 92,244 Common shares outstanding (000's) - diluted 98,437 Net asset value per share - basic $ 1.89 Net asset value per share - diluted $ 1.81 (1) Estimated at $110/acre Year Canadian Lt Sweet Crude 40 API ($C/Bbl) Western Canada Select 20.5 API ($C/Bbl) Alberta AECO-C ($C/MMBtu) Exchange Rate ($US/$C) 2017 $ $ $ 3.43 $ $ $ $ 3.17 $ $ $ $ 3.26 $ $ $ $ 3.67 $ $ $ $ 3.86 $ $ $ $ 3.97 $ $ $ $ 4.11 $ $ $ $ 4.23 $ $ $ $ 4.31 $ $ $ $ 4.41 $ $ $ $ 4.50 $ prices escalate at 2% thereafter 28

29 Summary of Unrisked Commercial, Contingent and Prospective Cardium and Badheart Resources Gross (MBoe) Working Interest (MBoe) Resource class (unrisked) P90 P50 Mean P10 P90 P50 Mean P10 Cumulative oil production (1)(2) Cumulative sales solution gas production (1)(2) Cumulative NGL production (1)(2) Remaining oil reserves (1)(3)(4) Remaining sales solution gas (1)(3)(4) Remaining NGL reserves (1)(3)(4) Total Cardium commercial Contingent Cardium oil resources 11,766 24,511 28,960 51,600 10,545 21,960 25,667 45,733 Contingent Cardium sales soln gas resources 1,045 2,133 2,629 4, ,011 2,330 4,097 Contingent Cardium NGL resources 449 1,010 1,239 2, ,098 2,041 Total Cardium contingent resources 13,260 27,654 32,409 58,107 11,728 24,462 28,676 51,453 Total Cardium discovered OOIP 140, , , , , , , ,028 Total Cardium discovered OGIP (5) Total Cardium discovered PIIP (4) 140, , , , , , , ,028 Prospective Cardium oil resources 11,622 27,001 33,106 62,730 8,019 18,630 22,843 43,284 Prospective Cardium soln gas resources 1,104 2,473 2,982 5, ,706 2,057 3,821 Prospective Cardium NGL resources 456 1,119 1,407 2, ,893 Total Cardium prospective resources 13,182 30,592 37,495 71,012 9,095 21,108 25,871 48,998 Prospective Badheart oil resources 3,992 8,259 9,628 17,089 3,372 6,977 8,134 14,436 Prospective Badheart soln gas resources 1,830 3,964 4,711 8,588 1,546 3,349 3,980 7,255 Prospective Badheart NGL resources Total Badheart prospective resources 5,952 12,537 14,730 26,434 5,028 10,591 12,444 22,331 Total prospective resources 19,133 43,129 52,225 97,446 14,123 31,700 38,316 71,329 Total Cardium undiscovered OOIP 136, , , ,229 94, , , ,488 Total Badheart undiscovered OOIP 47,330 84,295 92, ,127 39,985 71,212 78, ,828 Total undiscovered OGIP (5) Total undiscovered PIIP 183, , , , , , , ,316 Total unrisked PIIP (4) 324, , ,764 1,160, , , , ,344 (1) Effective May 1, (2) Boe equivalent (includes oil and gas production from Resource Reportsections). (3) Remaining volumes from reserve report dated Dec 31, 2016 less produced volumes from Jan 1, 2017 to May 1, (4) Low case reflects 1P reserves, best and high cases reflect 2P reserves. (5) Volume reflects free gas only (none in evaluated reservoir or study area). 29

30 BTNPV of Ikkuma s Contingent Cardium Development Program Discount Rate 0% 5% 10% 15% 20% BT Cash Flow NPV (MM$C) (1) The net present value of future net revenue attributable to Ikkuma s development pending contingent resources is based on Sproule s Q price deck and is determined before provision for interest, debt servicing and general and administrative expense and after the deduction of royalties, operating costs, development costs and abandonment and reclamation. An estimate of risked net present value of future net revenue of contingent resources is preliminary in nature and is provided to assist the reader in reaching an opinion on the merit and likelihood of Ikkuma proceeding with the required investment. It includes contingent resources that are considered too uncertain with respect to the chance of development to be classified as reserves. There is no certainty that the estimate or risked net present value of future net revenue will be realized. CAPEX assumptions, including forward efficiencies of multiple well-pad drilling (156 wells, average $2.7 mm/well, 207 boe/d IP, 181 Mboe/well, Sproule Q2 Price deck) Generates 68% ROI on these risked assumptions. (2) The NPV calculations include provisions for royalty reductions under Alberta s Modernized Royalty Framework. Under these incentives, a 5% minimum royalty is applied until the well revenue stream (before deductions) is greater than the calculated capital allocation of the well based on several variables, such as depth, lateral length, and frack volume tonnage. These calculations are outlined by the Alberta Government and are applied to new wells on crown lands. Once the revenue stream, added over a certain time, surpasses capital for drilling and completion, a sliding scale royalty is applied, based on price and volume, which is also outlined in Alberta s Modernized Royalty Framework. 30

31 Foothills delivers highest rate oil wells and leading economics in the basin. Payout in years at C$40 C$80/bbl. Emerging oil play at IKM has the potential to deliver similar returns. IP (bbl/d); EUR (MBoe) IP90 (boe/d) CARDIUM PLAY BOOK (1) EUR (mboe) IRR Wells >50% Gas IRR Wells >50% Oil 50% 45% 40% 35% 30% 25% 20% 15% 10% 5% IRR (%) 0 0% STOLBERG (1,2) IP WELL POPULATION Lochend (78% liq) Garrington (85% liq) Ferrier (38% liq) CARDIUM DATA BY AREA (1) Willesden Wilson Crk Grn (45% liq) (71% liq) East Pembina (82% liq) Cent Pembina (85% liq) W Pembina 82% liq) Edson (44% liq) Kaybob (78% liq) Wapiti (45% liq) Stolberg (87% liq) IP90 (boe/d) IP 90% Liquids 78% 85% 38% 45% 71% 82% 85% 82% 44% 78% 45% 87% EUR (mboe) EUR % Liquids 44% 60% 23% 30% 46% 68% 74% 67% 33% 55% 27% 51% Cost ($mm) $2.9 $2.5 $2.9 $2.7 $2.2 $2.2 $2.4 $2.5 $2.5 $2.5 $2.9 $3.6 Sample Wells NPV10* ($mm) $(0.1) $0.2 $1.5 $0.8 $0.0 $0.7 $0.9 $0.7 $0.0 $1.4 $0.3 $2.3 IRR 9% 12% 25% 16% 10% 18% 19% 19% 10% 24% 13% 43% Breakeven WTI** $49 $45 $24 $36 $49 $40 $39 $40 $48 $34 $44 $31 Top Operators by Hz. Prod'n: Pengrowth Pengrowth Orlen Bellatrix Tamarack Bonterra ARC Lightstream Long Run TORC Long Run Manitok Lightstream Whitecap CNRL Penn West OMERS ARC Penn West Vermilion TORC Conoco Modern Petrus Orlen Exxon Petrus Lightstream Regent Whitecap Bellatrix Whitecap Successor Repsol Husky Direct Enrg. (1) TD Industry Note, June (2) Sample population includes wells that penetrated Cordel oil pool in , which lowers Stolberg average EUR and IP. 31

32 More than 3,500 HZ wells have tested various Cardium deep basin oil pools (see appendix). Only two large foothills Cardium oil pools produced to date in the WCSB (Cordel and Stolberg). (2) Prod. Rate (bbl/d) OIL PD RATE (ALL CARDIUM DEEP BASIN HZ WELLS, IP30) Oil CD Rate GOR Well Count =3, GOR (scf/bbl) Foothills oil pools yield the highest returns due to enhanced permeability Months Expected oil recovery typically much higher in fractured foothills reservoirs, as indicated in graph to right. Based on regional analysis, oil recovery for the foothills Cardium at Narraway is expected to be higher than the deep basin reservoirs with comparable porosities. (1) EUR for new wells cannot be estimated at present. (2) WCSB Western Canada Sedimentary Basin; also see Appendix. 32

33 Discovered more than 20 years ago. Peak production of 5,100 Bbls/d; individual wells with production potentially surpassing 1 MMBoe. Early wells offset vertical wells with approximately similar initial rates and cumulative production to Ikkuma s Cardium of the Northern Alberta Foothills. Comparable reservoir quality to Ikkuma s Northern Alberta Foothills Cardium, though not as complexly deformed. Stolberg Cardium 7,000 6,000 5,000 4,000 3,000 2,000 1,000 STOLBERG CARDIUM 5,100 Bbl/d 7,520 boe/d peak prod. - Jan-12 May-12 Sep-12 Jan-13 May-13 Sep-13 Jan-14 May-14 Sep-14 Jan-15 May-15 Sep-15 Jan-16 May-16 Oil (bbl/d) GOR (scf/bbl) 33

34 An example of a large resource captured through horizontal drilling in shallow bypass reservoirs: IP: bbl/d Discovery vertical well (1997), w5. IP Bbls/d. Produced 30 Mbbls. Source: Geoscout Source: Geoscout 30 X multiple of vertical vs. horizontal. IP: ~1,000 bbl/d Produced >200 Mbbls 52 API oil and 1 Bcf in 20 months. 600 bbl/d This well was not stimulated, and free-flowed to surface for all of its production history. 400 bbl/d 200 bbl/d Source: Geoscout Source: Geoscout 34

35 Summary (HZ Multiplier) IP-X EUR-X Elm/Wapiti South-OIL (all wells outside Wapiti Pool) Elm/Wapiti (near offsets) Stolberg Harme-Oil (32-3) Kaybob ( ) Pembina (45-11,12) gasy IKM Alberta Foothills Vertcal Well # ,000 Vertcal Well #2 75 n/a ,000 Use Elm/Wapiti near offset multlier 1, ,215 Vertical - HZ Well Multiplier: the Cardium Formation in Elmworth / Wapiti has the most similar reservoir characteristics, based on logs. On average, horizontal wells in Wapiti benefit from a 9.3x increase on IP, 6.8x increase on EUR when compared to near offset vertical wells. Elm/Wapiti-Oil (near offset to vertical well HZ Vert (one well), offset pool is conv. Wapit Peak Prod. EUR Peak Prod. Rate EUR bbl/d bbl bbl/d bbl Mean 1 well 36 17, ,072 S-Mean ,376 Median ,706 Count Std. Dev ,304 r² Peak (bbl/d) EUR (Mbb) Dist ,909 Min ,597 P ,742 P ,009 P ,356 P ,798 P ,508 P ,198 P ,284 P ,299 P ,579 P ,075.1 P ,580.3 P10 1, ,914.9 P1 1, ,411.9 Max 1, ,411.9 Elm/Wapiti South-OIL (all wells outside Wapiti Pool) HZ Vert (one well), offset pool is conv. Wapiti Peak Prod. EUR Peak Prod. Rate EUR bbl/d bbl bbl/d bbl Mean 1 well 36 17, ,597 S-Mean ,221 Median ,378 Count Std. Dev ,055 r² Dist Peak (bbl/d) EUR (Mbb) Min ,931 P ,435 P ,862 P ,901 P ,555 P ,471 P ,512 P ,009 P ,510 P ,017 P ,819.6 P ,838.9 P ,529.8 P ,703.5 Max 1, ,411.9 The average of the two Cardium wells within the foothills trend was used for an expected vertical IP of 149 Bopd. Applying the Wapiti HWM to this number yields an expected horizontal IP of 1378 Bopd and 212,215 Bbls EUR. HEAVILY RISKED well IP of Bopd were used for modelling. Note: Stolberg average well multiplier is higher due to the natural fracture system in place (unstimulated vs stimulated). 35