Certain information with respect to Ikkuma Resources Corp. (“IKM” or the “Corporation”) included in this presentation constitutes forward-looking information under applicable securitieslegislation. Forward-looking information typically contains statements with words such as “anticipate”, “believe”, “expect”, “plan”, “intend”, “estimate”, “propose”, “project” or similarwords suggesting future outcomes or statements regarding an outlook. Forward-looking information in this presentation may include, but is not limited to, completion of the acquisition (the“Acquisition”) of certain assets located in the Alberta Foothills as well as the British Columbia Deep Basin (the “Assets”); completion of the disposition of 51% of Ikkuma’s trunk line andassociated facilities (the “Infrastructure Disposition”); completion of the flow-through offering; funding of the purchase price of the Assets; the Corporation’s expectation that the borrowingbase under its credit facilities will be increased following completion of the Acquisition; the performance characteristics of the Assets; the anticipated benefits of the Acquisition; theanticipated shut-in of 4,400 BOE/d by the vendor of the Assets (the “Vendor”) in September 2017; the impact of the Acquisition on the Corporation’s production, reserve; inventory, cash flowand financial condition; potential future OPEX reductions; expected decline rates; estimates of reserves, resources and the net present value of future net revenue associated with the bestestimate of the Corporation’s development pending contingent resources; potential flow rates from recently completed wells, the number of de-risked, low risk drilling locations, the numberof offset locations, the timing of future drilling operations, the potential future OPEX reductions, expected future well flow rates, the type and timing of capital expenditures. the estimatedreplacement 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 ata $3.00 to $10.00 per barrel premium to Edmonton light crude, the potential 42 well, four year Foothills light oil pool drilling program with a projected $127 MM CAPEX requirement or thepotential 50 well, four year Foothills light oil pool drilling program with a projected $185 MM CPEX requirement, and the annualized cash flow and peak production amounts applicablethereto, 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 producingreserves 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 basinreservoirs.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. Althoughmanagement believes that the expectations reflected in its forward-looking information are reasonable, undue reliance should not be placed on forward-looking information because therecan 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 maderegarding and are implicit in, among other things, expectations and assumptions concerning the performance of existing wells and success obtained in drilling new wells, anticipatedexpenses, 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 andassumptions 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 thosecurrently 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 indevelopment, exploration and production; delays or changes in plans with respect to exploration or development projects or capital expenditures; the uncertainty of reserve and resourceestimates; the uncertainty of estimates and projections relating to production, costs and expenses, and health, safety and environmental risks), commodity price and exchange ratefluctuations and uncertainties resulting from potential delays or changes in plans with respect to exploration or development projects or capital expenditures. The recovery and reserve andresource estimates contained in this Corporate Presentation are estimates only and there is no guarantee that the estimated reserves and resources will be recovered. These risks and otherrisks are set out in more detail in Ikkuma’s Annual Information Form for the year ended December 31, 2016.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 materiallyfrom 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 thedate 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.Certain information set out herein may be considered as “financial outlook” or “future oriented financial information” within the meaning of applicable securities laws. Financial outlook orfuture oriented financial information in this presentation was made as of the date of this presentation. The purpose of this financial outlook is to provide readers with disclosure regardingIkkuma’s reasonable expectations as to the anticipated results of its proposed business activities for the periods indicated. Readers are cautioned that the financial outlook may not beappropriate for other purposes.

Non-IFRS MeasuresThis presentation contains certain financial measures that do not have a standardized meaning prescribed by IFRS. These non-IFRS financial measures may not be comparable to similarmeasures presented by other issuers. Funds from operations and operating netback are not recognized measures under IFRS. Management uses certain industry benchmarks such asoperating netback to analyze financial and operating performance. This benchmark as presented does not have any standardized meaning prescribed by IFRS and therefore may not becomparable with the calculation of similar measures for other entities. Funds from operations represents cash provided by operating activities before changes in operating noncash workingcapital and decommissioning obligation expenditures. The Corporation considers it a key measure as it demonstrates the ability of the Corporation’s continuing operations to generate thefunds flow necessary to fund future growth through capital investment. Operating netback equals total petroleum and natural gas sales, realized gains and losses on commodity contracts,less royalties, operating costs and transportation costs calculated on a BOE basis. Management considers operating netback an important measure to evaluate its operational performanceas it demonstrates its field level profitability relative to current commodity prices. Reconciliations of funds from operations and operating netback to the most directly comparable measuresspecified under IFRS are contained in the Corporation’s management discussion and analysis, copies of which are available on SEDAR.

2

BOE DisclosureThe 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 barrelsof 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 BOEconversions 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 giventhat 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) bblsmeans barrels; (vi) mbbls means thousand barrels; (vii) mmbbls means million barrels; (viii) bbls/d means barrels per day; (ix) bcf means billion cubic feet; (x) mboe means thousand barrels ofoil equivalent; (xi) mmboe means million barrels of oil equivalent and (xii) boe/d means barrels of oil equivalent per day.

Future Drilling LocationsUnless otherwise specified, the information in this Corporate Presentation pertaining to potential drilling opportunities or drilling inventories is based solely on internal estimates made bymanagement and such locations have not been reflected in any independent reserve or resource evaluations prepared pursuant to NI 51-101, other than the Resource Assessment (ashereafter defined). Similarly, unless otherwise specified, the information in this Corporation Presentation pertaining to targeted reserve volumes from future drilling is intended to indicatethat 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 onaverage ultimately generate the indicated volumes. This Corporate Presentation discloses potential drilling opportunities which are unbooked locations and are internal estimates based onthe 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 theResource 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 onevaluation 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 nocertainty 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 dependupon 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 certainof 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 fartheraway 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 suchlocations and if drilled there is more uncertainty that such wells will result in additional oil and gas reserves, resources or production. Of the potential 150+ drilling opportunities shown onp.17 and p.21, six are proved plus probable locations identified in the Reserves Report.

Well Test ResultsCertain 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 hydrocarbonrecovery 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 beconsidered preliminary until such analyses have been completed.

Presentation of Oil and Gas ResourcesIkkuma engaged Deloitte LLP (“Deloitte”) to audit an internal resource evaluation of light oil and gas attributable to Ikkuma’s interest in the Cardium and Badheart formations of the northernAlberta Foothills effective May 1, 2017 (the “Resource Assessment”). See Ikkuma’s press release dated June 5, 2017 entitled “Ikkuma Resources Announces Resource Study of its Large LightOil Discovery” (the “June 5 Press Release”).Certain reserves data included in this presentation are based on an independent reserves evaluation of certain oil and gas assets in the Foothills area of Alberta (the “Central Alberta FoothillsAssets”) effective June 30, 2017 (the “Deloitte Report”) prepared by Deloitte and based on Deloitte’s price forecast as at March 31, 2017 (the “Deloitte Price Forecast”) and independentreserves assessments on the Assets other than the Central Alberta Foothills Assets (the “BC and Other Alberta Assets”) effective December 31, 2016 (the “GLJ Reports”) prepared by GLJPetroleum Consultants Ltd. (“GLJ”) and based on GLJ’s price forecast as at December 31, 2016 (the “GLJ Price Forecast”), prepared for the vender of the Assets (the “Vendor”). See Ikkuma’spress release dated August 15, 2017 entitled “Ikkuma Resources Corp. announces $34 million strategic Foothills asset acquisition, material increase in production and cash flow, partial sale ofexisting pipeline infrastructure for $20 million, and $10 million flow-through equity financing”.

3

The estimates of reserves and future net revenue for individual properties may not reflect the same confidence level as estimates of reserves and future net revenue for all properties, due tothe effects of aggregation.

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 (includingcontingent 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 theundiscovered resources (including prospective resources) disclosed in this Corporate Presentation, there is no certainty that any portion of the resources will be discovered. If discovered, thereis 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 bemisleading 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 differingprobabilities of recovery associated with each class as explained below or in Ikkuma’s Annual Information Form for the year ended December 31, 2016.

Resources and ProductionResources encompass all petroleum quantities that originally existed on or within the earth’s crust in naturally occurring accumulations, including discovered and undiscovered (recoverableand 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, tobe contained in known accumulations, prior to production, plus those estimated quantities in accumulations yet to be discovered. “Total resources” is equivalent to “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 PIIPincludes production, reserves and 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 technologyunder 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 isreferred to as prospective resources; the remainder is unrecoverable.

3

5

(1) Prior to giving effect to the Acquisition, the FT Equity Issue and the Infrastructure Disposition.(2) $10 million FT Equity Issue assuming a price of $0.82/share (as disclosed in the August 15, 2017 press release). (3) Includes stock options exercisable into 6.9 million common shares at an exercise price of $0.90 per share, warrants to purchase 6.8 million common shares at an exercise price of $0.86 per share and

warrants to purchase 3.3 million common shares at an exercise price of $1.00 per share. (4) Pro forma funds from operations per share was calculated based pro forma operating netback of $31.80 million less pro forma general and administrative expenses of $6.6 million and pro forma annual

finance costs of $2.2 million.(5) Based on current production. Excludes 4,400 BOE/d of production that is expected to be shut-in by the Vendor in September 2017.(6) Funds from operations and Operating Netback are non-IFRS measures. See “Non-IFRS Measures”.(7) Operating netback for Ikkuma is based on Ikkuma’s internal forecast for the year ending December 31, 2017 (updated to include actual results for the six months ended June 30, 2017), using an

estimated AECO natural gas price of $2.50/Mcf for unhedged natural gas production ($2.86/Mcf for 26 MMcf of hedged natural gas production) and assumes a 5% royalty rate, and $10.00/BOE operating expenses (including transportation).

(8) Operating netback for the Assets is an annualized estimate for the year ending December 31, 2017, based on recent lease operating statements provided by the Vendor using an estimated AECO natural gas price of $2.50/Mcf and assumes a 4% royalty rate, $13.29/BOE operating expenses (including transportation), and $10 million of sulphur revenue per year. Operating netback for the Assets does not include the potential 10-30% field operational cost savings identified above, which are expected to commence upon closing of the Acquisition.

(9) Production base decline was calculated using historical production rates and is an annualized weighted average of declines of the purchased Assets and declines of Ikkuma’s existing assets, based on lease operating statements over the last 6 to 12 months. Decline estimates may not reflect significant well or field run time issues during the last 6-12 months.

(10) LLR (Licensee Liability Rating, AER Directive 006). LLR Rating is a prescribed calculation by the AER, defined in AER Directive 006 as the ratio of the licensee’s eligible deemed assets to its deemed liabilities for its P&NG interests. Ikkuma’s LLR rating is as submitted to the AER and the Vendor provided the calculation for the acquired Assets. The pro forma LLR rating is the ratio of the pro forma deemed assets to the pro forma deemed liabilities.

Ikkuma(1) Acquisition FT Equity Issue(2) Pro FormaIncrease -

Decrease (%)Outstanding shares (M)

- Basic 94,300 12,195 106,495 13%

- Fully diluted(3) 111,450 12,195 123,645 11%

Funds from operations per share(4)(6)

- Basic $ 0.09 $ 0.22 130%

- Fully diluted(3) $ 0.08 $ 0.19 134%

Production (BOE/d)(5) 6,500 14,300 20,800 220%

Operating Netback ($MM)(6) $ 16.09(7) $ 15.71(8) $ 31.80 98%

Production Base Decline(9) 16% 8% 11% -28%

LLR Rating(10) 4.63 10.6 7.62 65%

Net Developed Land (acres) 56,883 151,767 208,650 267%

Net Undeveloped Land (acres) 177,037 246,270 423,307 139%

Total Land (acres) 233,920 398,037 631,957 170%

6

Why….

Accretive on many levels, production, PDP valuation, land holdings, infrastructure.

Funds from operations per share increases >100%.

Production increases >200%, with lower corporate base decline of 10-15%.

Adds >14,000 BOE/d.

Provides stable cash flow for the exploitation of many bypassed shallow pools, including oil

at Narraway.

Deal adds 8 more oil sections to existing Narraway oil pool (IKM discovery).

Team has identified 28,000 BOE/d of bypassed oil and gas opportunities on the asset.

5,100 BOE/d identified in near term recompletions, reactivations, and reentries.

Purchase price equates to $85/acre just for land value alone (all lands).

WI in Stolberg Oil pool, which was discovered by the IKM team; access to offset prospects.

7

Why…

EOR opportunity in 3 existing Cardium pools.

Post acquisition IKM is more attractive to investors.

Stable, expanded production is anticipated to provide significant, self-sustaining cash-flow to fund the Narraway oil development program (613 MMbbl Gross, 486 MMbblNet PIIP(6)); this light oil pool ranks as one of the largest discovered conventional oil pools in Western Canada in the last 3 decades.(7)

The IKM team was involved in the buildout of these assets.

Asset includes significant underutilized infrastructure (working interest 1,327 km of pipelines, 5 major facilities and 10 minor facilities), which can be utilized to exploit bypassed oil and gas zones.

The Assets include 5,100 kilometres of 2D and 143 square kilometres of 3D seismic data.

(3) Based on a purchase price of $34 million and current production of 14,300 BOE/d. The purchase price is subject to closing adjustments.

(4) Operating netback is a non-IFRS measure. See “Non-IFRS Measures”.(5) Operating netback for the Assets is an annualized estimate based on recent

lease operating statements provided by the Vendor using an estimated AECO natural gas price of $2.50/Mcf and assumes a 4% royalty rate, $13.29/BOE operating expenses (including transportation), and $10 million of sulphur revenue per year.

ASSET SUMMARY

Purchase Price(1) $ 34,000,000

Production at closing (BOE/d)(2) 14,300

METRICS (net of undeveloped land and seismic)(3)

$/BOE/d $ 2,369

$/Acreage Acquired $ 85.42

Purchase price/Operating Netback(4,5) 2.2 X

(1) Effective date of July 1, 2017, subject to closing adjustments. Purchase price does not include the $20mm sale of current trunk line to midstream operator (net of this, purchase price is $14mm).

(2) Current production is 18,700 BOE/d. 4,400 BOE/d is expected to be shut-in by the Vendor in September 2017.

(6) For complete disclosure of PIIP (petroleum initially in place), see June 5th press release.(7) Based on public data in Geoscout.

8

Proceeds from the sale of 51% IKM’s existing Trunk Line ($20 MM) funds most of the acquisition, while allowing participation in future midstream revenue opportunities.

Corporation’s lenders (ATB and TD) have estimated an increase of $15 mm in the credit facility to $40mm which is forecasted to be unused on closing as the remainder of the purchase price to be paid with available cash balances.

Flow through funding of $12.5 million at $0.82/share, facilitates further exploitation of large Cardium oil pool at Narraway.

Balance sheet improves through the Acquisition.

$0

$10,000

$20,000

$30,000

$40,000

$50,000

$60,000

$/BO

E/d

Vendor

Natural Gas Transactions - Production Metric Ranking2013 - Present, No Adjustments for Land, Seismic, etc.

Source: GMP FirstEnergy, August 2017

Ikkuma August 2017Foothills Acquisition

9

Sound Balance Sheet

Low Decline (sustainability)

Production Replacement (low cost recompletions/re-entries, infill drilling)

Share Value

Underexploited Conventional Oil and

Gas Reservoirs(compliments the

Narraway discovery)

Sustainable Light Oil Program Greatly Increased Portfolio of Bypassed Reservoirs

Cash Flow Backed by Very Low Corporate Base Decline

Greater Access to Available Underutilized Owned Infrastructure

Focus on Foothills Remains a Core Value Driver

Balanced Portfolio Reduces Corporation’s Drilling Risk

10

Source: Averaged interpreted base declines (BMO, May, 2017)

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

11

Large contiguous land base makes IKM the second largest Alberta Foothills producer.

Low decline, (pro forma ~11%).

Area is rich in bypass oil and liquids rich, sweet gas reservoirs.

IKM team operated this asset previously.

Acquisition consolidates Narraway Oil Pools.

Existing, dense infrastructure (roads and pipelines) can be utilized to exploit many shallow bypass zones.

Infrastructure Footprint expanded; includes 1,327 km of pipelines, 5 major facilities, and 10 minor facilities.

Edmonton

Calgary

Northeastern Edge of Foothills Belt

Existing Core Area

Acquired Core Area

Existing IKM Lands

Existing Oil Pools

Asset Lands

12

New working interest pipelines

Other pipelines within purchased land now partly or wholly owned by IKM

Purchased Lands

Edmonton

Calgary

New Core Area, Southern Part, with 2 Existing Light Oil Pools

Stolberg discovered on bypass reservoir data by IKM team.

All pools with EOR and step-out or infill drilling opportunities.

Extensive prior operational experience (drilling and production buildout) with these assets.

28,000 boe/d of bypassed pay identified.

5,000-6,000 boe/d recompletions.

13

Edmonton

Calgary

Cordel Oil Pool

Stolberg Oil Pool

Brown Creek Oil Pool

Stolberg Oil PoolCordel Oil Pool (downplunge

section)

Mannville, Belly R., and Cardium prospectivity

A BA

B

14

Brown Creek oil and gas pools (Cardium)

Most gas currently producing from deeper formations (Turner Valley)

Multiple thrust sheets containing bypass Mannville/Notikewin(brown), Cardium (green), and Nikanassin (pink)

A

B

A B

New Core Area, Northern Part, with one Existing Light Oil Pool

Heavily structured.

Multiple thrust repeats contain fractured bypass pay, including Cardium, Notikewin, Mannville, and Nikanassin formations.

Thick bypassed conventional Mannville reservoirs with liquids-rich gas (10-20 bbl/mmcf).

Numerous sour gas recompletion and drilling opportunities; many undrilled thrust sheets remain.

Cordel Oil Pool

Stolberg Oil Pool

Brown Creek Oil Pool

15

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.

51% of trunk line is now owned by a midstream company, sold for a total consideration of $20mm.

32%

20%

12%

11%

7%

2%

(1) Approximately 16% of total production is in southern Alberta Foothills.(2) Estimated replacement value of $300-350 MM.

Area production, as a percent of total (1)

IKM Trunk Pipeline

In the southern part of IKM Existing Core Area, there is at least 120 MMcf/d gas processing and transporting capability.

Co-ownership with a midstream company provides potential to bring significant 3rd party volumes through underutilized asset base.

Potentially lower OPEX and low decline conventional reservoirs provides long term value in a volatile commodity environment. Approximately 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.

EdsonHorseCopton (35% WI)Leland (39% WI)Unused capacity ~120 MMcf/d

ElmworthNarraway (7% WI)Unused capacity ~100 MMcf/d

IKM Pipeline

16

17

> 4,500 producing Cardium HZ wells in western Canada.

Many juniors are exploiting Cardium pools in the deep basin, including: TORC (Kaybob, Rosevear,

Carrot); Vermilion, Bellatrix, Bonterra,

Arc in Pembina; Bonavista, Yangarra, Taqa,

Tourmaline (Willesden 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.

Cardium Oil and Gas Pools

Narraway

18

Discovery Well #1, 1999 (vertical well), IP 220 bbl/d, 31Mbbl

Q1, Q2 Drilling Operations

Two New Oil Pool Discoveries:8-31-63-11W6 and 2-1-64-12W6

Approximate Oil Pool Outline

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%.

150+ potential drilling opportunities 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.

19

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.

Foothills Fractured Conventional Play

High permeability “sweet spots” anticipated in many of the 150+ potential drilling opportunities 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.

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.

1400

1420

1440

1460

1480

1500

1520

1400

1420

1440

1460

1480

1500

1520

Density PorosityGamma Ray

Dep

th (m

)

Cardium

20

Berland

E Pembina

Edson

Ferrier

Fir Harme

Kaybob

Lochend

Med River

N Pembina

Notin-Carrot

NW Pembina

Pine Creek

Rosevear

Will Grn

Wilson Ck

Wapiti

Kakwa

Cordel

Stolberg

-

50,000

100,000

150,000

200,000

250,000

300,000

- 0.2 0.4 0.6 0.8 1.0 1.2 1.4

EUR

(BBL

)

PhiH

EUR vs PhiH

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.

(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.

Deep Basin Oil Pools

Foothills Oil Pools

21

0.10

1.00

10.00

100.00

1,000.00

10,000.00

1920 1930 1940 1950 1960 1970 1980 1990 2000 2010 2020

OO

IP (M

MBO

)

Discovery Date

Alberta and BC Field OOIP vs Discovery Date

Alberta and BC Fields IKM Narraway Expon. (Alberta and BC Fields)

Gross in place oil on Ikkuma lands: pools size ranks 28th 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.

Source: Geoscout

Narraway (gross PIIP, Cardium)*

* 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.

22

150+ potential drilling opportunities

Pro forma cash flow allows program to be self-funded ,and corporate gas production declines can be replaced by high netback oil

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)

50 wells over 4 years, 2 rigs 2019/2020:

Projected $185 MM CAPEX requirement (2,4)

Peak production 5,858 boe/d Peak stand-alone annualized cash flow of $86 MM/yr (3)

(1) Narraway Resource Report, released June 5th, 2017, indicates 485 MMBoe WI PIIP.(2) IP 250 boe/d, $3.5 – 4.5 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.

0

100

200

300

400

500

600

0% 50% 100% 150% 200%

IP B

OE/

d

IRR (%)

Single Well IRR vs IP (MRF)(3)

IP (bbl/d)

Why own IKM stock?

1. Transformational Acquisition Purchase metric adds reserves and production at a market-leading price with no dilution. Low decline provides stable cash flow for a self-funded light oil program. Lowering of OPEX will provide significant added cash flow. Opportunity portfolio (drilling and recompletion inventory) now diversified and expanded Purchased oil pools have development drilling and EOR and opportunities. IKM team operated much of the asset previously, and now is in an ideal position to decrease

field expenses and exploit shallower reservoirs.

2. Unique Business Model Matched with the Right Team One of the largest light oil pool discoveries in the last 30 years in the basin highlights the

underexploited nature of the foothills. Significant recompletion inventory. Underexploited part of the basin: prolific conventional reservoirs proven to exist in bypass zones,

based on Ikkuma’s recompletion results to date.

3. Clear Path to Growth Significant light oil pool discovery: 485 MMBoe WI PIPP.(1)

Multiyear drilling inventory (oil and gas) that has been greatly expanded with acquisition. Self-funding entity with very low corporate base decline.

23

(1) For complete disclosure of PIIP (petroleum initially in place), see June 5th press release.

24

ANALYST COVERAGE

Acumen Capital Trevor Reynolds

Beacon Securities Kirk Wilson

Clarus Securities Rob Pare

Desjardins Chris MacCulloch

GMP First Energy Cody Kwong

Haywood Securities Darrell Bishop

PI Financial Brian Purdy

TD Securities Juan Jarrah

MANAGEMENT

Tim de FreitasPresident & CEO

Yvonne McLeod Senior VP Engineering

Greg Feltham VP Exploration

Rich RoweVP Land

Kim BendersInterim CFO & Corporate Controller

LEGAL COUNSEL

Borden Ladner Gervais LLP

TRANSFER AGENT

Alliance Trust Company

RESERVE & RESOURCE EVALUATORSSproule and Associates Ltd.

Deloitte LLP

BOARD OF DIRECTORS

Robert Dales (Chairman)

Dave Anderson

Dorothy Else

Tim de Freitas

Charle Gamba

William Guinan (Corporate Secretary)

Mike Kohut

CORPORATE OFFICE

Suite 2700, 605 – 5th Avenue SW

Calgary, AB T2P 3H5

T: (403) 261-5900

www.ikkumarescorp.com

BANKS

The Toronto-Dominion Bank

ATB

AUDITOR

KPMG LLP

25

26

Reserves Category NPV 10% (M$)

Oil (Mbbl)

Liquids (Mbbl)

Gas (MMcf) MBOE

Developed Producing $ 103,551 126.1 432.5 78,501 13,642.2

Developed Non-Producing $ 14,446 - 12.8 13,354 2,238.4

Undeveloped $ 13,761 139.3 13.7 23,384 4,050.3

Total Proved $ 131,759 265.4 459.0 115,239 19,930.9

Probable $ 58,272 533.2 108.1 41,798 7,607.6

Total proved plus probable $ 190,031 798.6 567.1 157,037 27,538.5

Based on Dec 2016 Consensus Price Forecast (Sproule, McDaniel, GLJ)

YearCanadian 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 $ 68.24 $ 53.38 $ 3.43 $ 0.76

2018 $ 73.16 $ 58.95 $ 3.17 $ 0.79

2019 $ 76.25 $ 62.70 $ 3.26 $ 0.82

2020 $ 79.37 $ 65.48 $ 3.67 $ 0.83

2021 $ 82.56 $ 68.39 $ 3.86 $ 0.85

2022 $ 84.85 $ 70.49 $ 3.97 $ 0.85

2023 $ 87.15 $ 72.58 $ 4.11 $ 0.85

2024 $ 89.50 $ 74.73 $ 4.23 $ 0.85

2025 $ 91.89 $ 76.88 $ 4.31 $ 0.85

2026 $ 94.01 $ 79.08 $ 4.41 $ 0.85

2027 $ 95.85 $ 80.64 $ 4.50 $ 0.85

2028+ prices escalate at 2% thereafter

NET ASSET VALUE PER SHARE at Dec 31, 2016

10% NPV of 2P P&NG reserves, before tax ($000's) $ 190,031

Undeveloped land (1) ($000's) $ 20,850

2016 YE Net Debt (Audited) ($000's) $ (32,465)

Net asset value ($000's) at Dec 31, 2016 $ 178,416

Common shares outstanding (000's) - basic 94,244

Common shares outstanding (000's) - diluted 98,418

Net asset value per share - basic $ 1.89

Net asset value per share - diluted $ 1.81

(1) Estimated at $110/acre

27

AECO Edmnt Lt AECO Edmnt Lt

year C$/Mcf C$/bbl C$/Mcf C$/bbl

2017 2.58$ 64.85$ 2.79$ 69.33$

2018 2.55$ 65.80$ 2.93$ 72.26$

2019 2.80$ 67.95$ 3.05$ 75.00$

2020 3.00$ 69.15$ 3.22$ 76.36$

2021 3.20$ 71.75$ 3.39$ 78.82$

2022 3.35$ 77.65$ 3.58$ 82.35$

2023 3.60$ 77.65$ 3.76$ 85.88$ 2024 3.85$ 77.65$ 3.95$ 89.41$

2025 4.20$ 77.65$ 4.03$ 92.94$ 2026 4.45$ 77.65$ 4.11$ 95.61$

Deloitte (March 31, 2017) GLJ (Jan 1, 2017)Price Files

(1) Only developed reserves were evaluated for the Acquisition.(2) Before tax net present value based on a 10% discount rate and the Deloitte Price Forecast in respect of the Central

Alberta Foothills Assets and the GLJ Price Forecast in respect of the BC and Other Alberta Assets. Estimated values of future net revenues do not represent the fair market value of the reserves.

(3) Reserves are the total company working interest in the Assets (operating and non-operating) before deduction of royalties and without including any royalty interest receivable on the Assets. Gross reserve estimates are based on the Deloitte Report (as at June 30, 2017 in respect of the Central Alberta Foothills Assets) and the GLJ Reports (as at December 31, 2016 in respect of the BC and Other Alberta Assets).

Evaluator Effective Date Category NPV10%

($M)(2) MBOE(3)

Kiskiu(1) GLJ 31-Dec-16PDP $ 6,473 540

TPP $ 7,378 671

Lynx(1) GLJ 31-Dec-16PDP $ 4,911 905

TPP $ 5,965 1,167

Hinton(1) GLJ 31-Dec-16PDP $ 561 67

TPP $ 665 86

Ekwan/Siera(1) GLJ 31-Dec-16PDP $ 15,461 2,605

TPP $ 8,495 3,388

Ansell Ram Deloitte 01-Jul-17PDP $ 99,400 25,925

TPP $ 128,500 33,571

28

Footnotes on next slide

Summary of Unrisked Commercial, Contingent and Prospective Cardium and Badheart Resources

29

(1) Effective May 1, 2017. The volumes in this table, other than cumulative production and reserves, have been presented on an unrisked basis, meaning that they have not been adjusted for the chance of commerciality. The unrisked PIIP includes several oil pools which may or may not been in geological communication. At present, five separate oil pools have been identified, but overtime, these may, in fact, prove to be in communication. The in place hydrocarbon volumes thus represent an arithmetic addition of all identified accumulations. Volumes include reserves assigned to existing horizontal wells by Sproule effective December 31, 2016. Reserves are included in the above table for completeness; however, reserves were not the focus of the Resource Assessment.

(2) Boe equivalent (includes oil and gas production from Resource Report sections).(3) Remaining volumes from Reserve Report less produced volumes from Jan 1, 2017 to May 1, 2017.(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).(6) “Gross” means 100% working interest in production, reserves or resources prior to deduction of royalty obligations. “Working interest” means in relation to Ikkuma’s interest in production,

reserves or resources, Ikkuma’s working interest (operating or non-operating) share pior deduction of royalty obligations, plus Ikkuma’s royalty interests in production or reserves.

30

BTNPV of Ikkuma’s Contingent Cardium Development Program

Discount Rate 0% 5% 10% 15% 20%

BT Cash Flow NPV (MM$C) 674.2 419.1 269.7 178.6 121.0

(1) The net present value of future net revenue attributable to Ikkuma’s best estimate (P50) risked development pending contingent resources isbased on Sproule’s March 31, 2017 price deck and is determined before provision for interest, debt servicing and general and administrativeexpense and after the deduction of royalties, operating costs, development costs and abandonment and reclamation. An estimate of riskednet present value of future net revenue of contingent resources is preliminary in nature and is provided to assist the reader in reaching anopinion on the merit and likelihood of Ikkuma proceeding with the required investment. It includes contingent resources that are consideredtoo uncertain with respect to the chance of development to be classified as reserves. There is no certainty that the estimate or risked netpresent value of future net revenue will be realized. CAPEX assumptions, including forward efficiencies of multiple well-pad drilling (156wells, 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, a5% minimum royalty is applied until the well revenue stream (before deductions) is greater than the calculated capital allocation of the wellbased on several variables, such as depth, lateral length, and frack volume tonnage. These calculations are outlined by the AlbertaGovernment and are applied to new wells on crown lands. Once the revenue stream, added over a certain time, surpasses capital for drillingand completion, a sliding scale royalty is applied, based on price and volume, which is also outlined in Alberta’s Modernized RoyaltyFramework.