Certain information with respect to Ikkuma Resources Corp. (“IKM” or the “Corporation”) included in this Corporate Presentation constitutes forward-looking information under applicablesecurities legislation. Forward-looking information typically contains statements with words such as “anticipate”, “believe”, “expect”, “plan”, “intend”, “estimate”, “propose”, “project” orsimilar words suggesting future outcomes or statements regarding an outlook. Forward-looking information in this Corporate Presentation may include, but is not limited to, completion ofthe acquisition (the “Acquisition”) of certain assets located in the Alberta Foothills as well as the British Columbia Deep Basin (the “Assets”); completion of the flow-through offering; fundingof the purchase price of the Assets; the Corporation’s expectation that the borrowing base under its credit facilities will be increased to $40 million following completion of the Acquisition; theperformance characteristics of the Assets; the anticipated benefits of the Acquisition; the impact of the Acquisition on the Corporation’s production, reserve; inventory, cash flow and financialcondition; potential future OPEX reductions; expected decline rates; estimates of reserves, resources and the net present value of future net revenue associated with the best estimate of theCorporation’s development pending contingent resources; potential flow rates from recently completed wells, the number of de-risked, low risk drilling locations, the number of offsetlocations, 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 higher likelihood of undeveloped reserves being converted to producing reserves in the near term, the Corporation’s futureoperations 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. 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 Corporate Presentation, assumptions havebeen 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 factorsand 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 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 Corporate Presentation is made asof 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 orotherwise, unless required by applicable securities laws. The forward-looking information contained in this Corporate 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 Corporate Presentation was made as of the date of this Corporate Presentation. The purpose of this financial outlook is to provide readers withdisclosure regarding Ikkuma’s reasonable expectations as to the anticipated results of its proposed business activities for the periods indicated. Readers are cautioned that the financialoutlook may not be appropriate for other purposes.

Non-IFRS MeasuresThis Corporate Presentation contains certain financial measures that do not have a standardized meaning prescribed by IFRS. These non-IFRS financial measures may not be comparable tosimilar measures 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 Corporate 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 perday; (v) bbls means 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 meansthousand barrels of oil 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 Sproule Report (as hereafterdefined). Similarly, unless otherwise specified, the information in this Corporation Presentation pertaining to targeted reserve volumes from future drilling is intended to indicate that inmaking 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 averageultimately generate the indicated volumes. This Corporate Presentation discloses potential drilling opportunities which are unbooked locations and are internal estimates based on theCorporation’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 SprouleReport, 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 ofapplicable 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 thatsuch 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 theavailability 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 theunbooked 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 awayfrom 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 locationsand 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 are proved plusprobable locations identified in the Sproule 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 Corporate Presentation are based on an independent reserves evaluation of oil and gas assets of Ikkuma effective December 31, 2016 (the SprouleReport), prepared by Sproule and Associates, and certain oil and gas assets in the Foothills area of Alberta (the “Central Alberta Foothills Assets”) effective December 31, 2016 (the “DeloitteReport”) prepared by Deloitte and based on Deloitte’s price forecast as at December 31, 2016 (the “Deloitte Price Forecast”) and independent reserves assessments on the Assets other thanthe Central Alberta Foothills Assets (the “BC and Other Alberta Assets”) effective December 31, 2016 (the “GLJ Reports”) prepared by GLJ Petroleum Consultants Ltd. (“GLJ”) and based onGLJ’s price forecast as at December 31, 2016 (the “GLJ Price Forecast”), prepared for the vendor of the Assets (the “Vendor”). See Appendix and Ikkuma’s press release dated August 15, 2017entitled “Ikkuma Resources Corp. announces $34 million strategic Foothills asset acquisition, material increase in production and cash flow, partial sale of existing pipeline infrastructure for$20 million, and $10 million flow-through equity financing”. An updated reserve report was also prepared for the Central Alberta Foothills Assets effective June 30, 2017. See Appendix.

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.

4

5

Directors

Dave Anderson

Bob Dales (Chairman)

Tim de Freitas

Dorothy Else

Charle Gamba

Bill Guinan (Corporate Secretary)

Mike Kohut

Management

Tim de Freitas, CEO

Kim Benders, Corporate Controller/Interim CFO

Greg Feltham, VP Exploration

Yvonne McLeod, SVP Engineering

Rich Rowe, VP Land

Team with long history of operations in the Alberta Foothills (area experts)

Numerous conventional/unconventional oil and gas reservoirs (underexploited), but in an area with low industry competition

One of the lowest base production decline in Canadian Junior/Intermediates (proforma ~11%)

Second largest Alberta Foothills producer

Extensive infrastructure(~1,800 km pipelines, numerous processing facilities), with proven value (51% pipeline sale for $20mm; no egress issues)

Recently acquired assets were operated by current Ikkuma team while at a major O&G Producer

Gas producer, with large under-developed light oil pools

6

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 Base Production with Free Cash Flow for Development and Exploration of Light Oil Opportunities

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

Significant Oil Upside Through Exploration and Development

7

Recently announced a transformational Foothills acquisition will approximately triple production to ~20,000 boe/d for $34 million

11% increase in S/O

60% increase in liquidity

>200% increase in production

~100% increase in CF

>150% increase in PDP reserve value

(1) Prior to giving effect to the Acquisition, the FT Equity (as hereafter defined) Issue and the disposition of 51% of Ikkuma’s interest in a trunk line and associated facilities.(2) Flow-through share offering for $12.5 million at a price of $0.82/share (as disclosed in the August 15, 2017 press release; the “FT Equity Issue”). (3) Fully diluted 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) Based on current production. Excludes 4,400 BOE/d of production that was shut-in by the Vendor in September 2017.(5) Operating Netback are non-IFRS measures. See “Non-IFRS Measures”.(6) 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).(7) 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.

(8) 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.

(9) Pre-acquisition Ikkuma reserves are based on the Sproule Report, as at December 31, 2016. Reserves in respect of the Asset are based on the Deloitte and the GLJ reports. Before tax net present value based on a 10% discount rate and Deloitte's price forecast, in respect of the Central Alberta Foothills Assets and GLJ's price forecast in respect of the BC and Other Alberta Assets (the "GLJ Price Forecast").

As At June 30, 2017(1) Post Acq. & Financing(2) % Change

Shares Outstanding(3) (mm) 94.3 (basic) / 111.5 (FD) 106.5 (basic) / 123.6 (FD) 13% / 11%

Market Capitalization - FD (Share Price as at Sept 25, 2017)

($mm) $78.1 $86.5

Credit Facility ($mm) $25.0 $40.0 60%

Insider ownership (%) 20% 9% 55%

Production(4) (boe/d) 5,800 18,000-21,000 ~200%

Base Decline(8) (%) 16% 11% 31%

2017 Cash Flow (Operating Netback)(5,6,7) ($mm) $16.1 $31.8 98%

PDP Reserves: Volumes(9) (mmboe) 13.6 48.7 257%

PDP NPV10% BT(9) ($mm) $103.55 $271.76 162%TPP Reserves: Volumes(9) (mmboe) 27.5 69.2 151%

2P NPV10% BT(9) ($mm) $190.03 $372.50 96%

8

Large contiguous land base rich in bypass oil and liquids rich, sweet gas reservoirs

Second largest Alberta Foothills producer

Low decline, (proforma ~11%)

Assets were operated by current Ikkuma team previously at large O&G companies

Acquisition consolidates Narraway Oil Pools

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

Edmonton

Calgary

Northeastern Edge of Foothills Play

Existing Core Area

Acquired Core Area

Existing IKM Lands

Existing Oil Pools

Acquired Lands

BC – Deep Basin Assets

Ft Nelson

9

(1) Reflects current production. Approximately 4,400 BOE/d was shut-in by the Vendor in September 2017.

(2) Operating Netback are non-IFRS measures. See “Non-IFRS Measures”. 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.

(3) Acquisition assets based on the Deloitte Report and the GLJ Reports. 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 forecast prices in respect of the BC and Other Alberta Assets.

Initial Purchase Price of $34 Million, Funded Through:

Sale of existing trunk-line infrastructure and associated facilities (51% working interest) for $20 million (closed October 23, 2017).

No punitive pipeline fees to the corporation.

Corporation’s lenders (ATB and TD) est. increase of credit facility to $40mm.

Net purchase price anticipated to be adjusted downward, due to exercised ROFRs.

Significant Benefits to Shareholders:

Accretive across all major measures while also reducing leverage ratios and increasing liquidity.

Increases production >200% while lowering corporate base decline to ~11% (from ~16% previously).

Increases Cash flow/Share >100%.

Provides stable cash flow for the exploitation of many bypassed shallow pools.

Adds 8 more oil sections to existing Ikkuma discovery at Narraway.

Includes underutilized infrastructure (working interest 1,327 km of pipelines, 5 major facilities and 10 minor facilities); 5,100 kilometres of 2D and 143 square kilometres of 3D seismic data.

Adds >100,000 BOE/d (gross) economic upside opportunities.

Asset SummaryPurchase Price ("PP") ($mm) $34.0Production(1) (boe/d) 14,300Operating Netback(2) ($mm) $15.7PDP Reserves(3) (mboe) 35,096PDP NPV10% (BT)(3) ($mm) $168,2062P Reserves(3) (mboe) 41,664Total Land (acres) 398,037

Acquisition Metrics (Not adjusted for $ 20mm infrastructure sale)PP/boe/d $2,378PP/ Operating Netback(2) 2.2xPP/PDP BOE $0.97PP/ PDP NPV10% (BT)(3) 0.2xPP/2P BOE $0.82PP/acre $85.42

Low decline with very high PDP NPV10% valuation

Purchase metric at historic low results in highly accretive metrics

10

$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,

Ikkuma August 2017Foothills Acquisition

IKM

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

11

Corporate History

2014 – Recap transaction raising gross proceeds of $150 million and acquired natural gas assets located in Western Canadian Foothills area for an aggregate purchase price of ~$145 million. One large purchase and 3 smaller asset purchases during 2014.

August 2017 – Entered into definitive agreement to acquire assets located in the Alberta Foothills and British Columbia Deep Basin for $34 million; expected to close in December, 2017.

Sold 51% W.I. in trunk line and associated facilities in existing northern Alberta Foothills properties for $20 million cash (closed October 23, 2017). No punitive fees to corporation. More than triples production and NPV10% value on reserves. Adds extensive infrastructure.

Reserves(2)

Production(1)

(1) Production for Q3, 2017 and later quarters is estimated. Once the Acquisition is closed and ROFRs exercised, a more accurate estimate of production will be released. The estimated production assumes no incremental volume adds and no capital spend. Q4, 2017 production assumes closing of the Acquisition in mid December. Deal closing into escrow is expected in November, 2017.

(2) Effective December, 2016, reserves for the acquisition are listed in the Appendix.

7,12

1

6,76

9

6,54

1

7,27

0

7,49

7

5,92

1

5,86

6

5,96

7

6,57

1

5,86

1

5,70

0 8,68

0

20,7

00

20,2

53

0

5,000

10,000

15,000

20,000

25,000

Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 Q1 Q2

2015 2016 2017 2018

Prod

uctio

n (b

oe/d

)

Base (boe/d) Acquisition (boe/d)

14.9

14.4

13.6

48.7

25.9

27.5

27.5

69.2

0

10

20

30

40

50

60

70

2014 2015 2016 2017-Acquisition

MM

Boe

PDP (mboe) 2P (mboe)

12

Opportunity to Create Value

Anticipated OPEX reduction of 10% to 30% on acquired Assets

Lack of recent well optimization

Significantly underutilized facilities

Limited drilling program on the Assets (other than the Stolberg light oil pool) since 2004

PDP Sensitivity Analysis – NPV10 BT

0

20,000

40,000

60,000

80,000

100,000

120,000

140,000

160,000

180,000

200,000

Gros

s Mcf

/d

8% Decline

Actual Forecast

Central Foothills Decline (Acquired Assets)

140.

80

155.

00

169.

60

199.

40

230.

00

245.

60

0%

20%

40%

60%

80%

100%

120%

$0

$40

$80

$120

$160

$200

$240

$280

0% 10% 15% 20% 25% 30%

% In

crea

se in

NPV

NPV

10%

(BT)

($m

m)

% OPEX Savings

Ram/Ansell Deloitte December 31, 2016 Increase in NPV

13

Source: GMP-FirstEnergy, October, 2017 (M. King)

Asset Field Netback (next 12 months – No Drilling) ($mm)

Low decline (proforma ~11%).

~2000 BOE/d production replacement each year to offset declines.

Historic recompletion capital efficiency is approx. $5,000 – 10,000/Boe/d, with a 2-3 year inventory identified to date.

$9,6

18

$14,

607

$19,

597

$24,

586

$29,

577

$26,

056

$31,

046

$36,

025

$41,

025

$46,

014

$42,

495

$47,

484

$52,

474

$57,

463

$62,

451

$58,

933

$63,

922

$68,

911

$73,

900

$78,

888

0% 10% 20% 30% 40%

Prof

orm

aCo

rpor

ate

Fiel

d N

etba

ck, $

/Yea

r

Acquisition OPEX savings$2.00/Mcf AECO $2.50/Mcf AECO $3.00/Mcf AECO $3.50/Mcf AECO

Est. Field Netback on GMP 2018 - AECO price forecasts

Could trade at 1X market cap, with 20% OPEX savings

14

“September Sea Surface Temperatures (SSTs) are now available, and we see downwardspikes in ocean temps everywhere, led by sharp decreases in the Tropics and SH,reversing the bump upward last month. The Tropical cooling in particular factors intoforecasters favoring an unusually late La Nina appearance in coming months.”

http://clivebest.com/blog/?p=8087

https://www.climate.gov/ensoWestern NA Circulation(1)

La Nina

Aug, 2017

Sept, 2017

http://notrickszone.com/wp-content/uploads/2017/07/Holocene-Cooling-Greenland-Ice-Sheet-Temps-Decreasing-Since-2005-Kobashi-2017.jpg

Global Temps

The HadCRUT4.5 temperature anomaly for September is 0.54Clower, a fall of 0.17C since August. Global temperature may notnecessarily result in NA arctic outbreak. There is also a strong linkto ocean circulation patterns.

TD Energy Fall (2017) Energy Outlook

Degree Day CountGlobal Temps (HadCRUT 4.5), September 2017

Record length of time with deviation from mean; i.e., persistent poor nat. gas demand

Nat. Gas Burn

High

Low

(1) This anomaly is likely part of the Pacific Decadal Oscillation or PDO; we are currently moving into an increasingly negative phase, which implies cooling in certain regions of the Pacific Ocean.

Blocking ridge has been linked to cooler eastern US temperatures

Large contiguous land base focused in the Foothills

Underutilized infrastructure

More than 100,000 (gross) boe/d identified, based on “bypass”

Acquisition expands infrastructure further with 1,327 km of pipelines, 5 major facilities, and 10 minor facilities

15

Edmonton

Calgary

Existing IKM Lands

Existing Oil Pools

Asset Lands

Ft Nelson

0

20,000

40,000

60,000

80,000

100,000

120,000

140,000

160,000

Sep-

04Se

p-05

Sep-

06Se

p-07

Sep-

08Se

p-09

Sep-

10Se

p-11

Sep-

12Se

p-13

Sep-

14Se

p-15

Sep-

16Se

p-17

Sep-

18Se

p-19

Sep-

20Se

p-21

Sep-

22

BOE/

d

Proforma Corporate BOE/d (Gross)

~11% Decline (Group Plot)

Actual Forecast

~20,000 BOE/d (net), 97% gas

Northeastern Edge of Foothills Play

Existing Core Area

Acquired Core Area

BC – Deep Basin Assets

Low decline deep gas, 2 Existing Light Oil Pools, numerous bypass zones

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.

TD report (June, 2016) shows Foothills Cardiumto be most economic in basin (see Appendix).

16

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

17

(1) NAB ‒ Northern Alberta Foothills; CAB ‒ Central Alberta Foothills; all numbers are gross. This is outside previous definition of the Central Alberta Assets and BC and other Assets.(2) B/E ‒ Breakeven.(3) EOR ‒ Enhanced Oil Recovery.(4) Ownership in 10 sections, with a single Montney vertical well test of 10mmcf/d on one of these sections.(5) Represent potential drilling locations. See “Future Drilling Locations”, as listed in the Sproule Report.

18

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.

Ikkuma 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.

Acquired Lands

Existing Lands

Trunk Line 51% disposition ($20mm)

19

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.

485 MM BOE WI PIIP (Deloitte Report, 2016)(1)

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/Bblpremium to Edmonton Light.

(1) Details of the Deloitte Report were disclosed in a press release, June 5, 2017.

1.00

10.00

100.00

1000.00

1 7 13 19 25 31 37 43 49 55 61 67 73 79 85 91 97 103

109

115

121

127

133

139

145

151

157

163

169

175

181

187

193

199

205

211

217

223

229

235

241

247

253

259

265

271

277

283

289

295

301

307

BBL/

d, B

OE/

d

Approx. 320 Days Production

8-31, First Year Production

BOE/d BBL/d

20

25 MBoe to date, 51 API oil

Operations to Date

4 HZ wells, with first well still pumping at ~32-70 Boe/d, 51 API oil, approx. 38% exponential decline in first year.

As few as 8 stages out of 16 frac ports were effectively stimulated, resulting in matrix-type production decline.

Flow back of completion fluids and workovers underway on other three other wells.

Wells 2-4 intersected excellent reservoir quality and light oil charge, but reservoir pressure is variable across individual pools.

OPEX Reduction 20% reduction in OPEX increases NPV10% by 60%; cash flow increases $4-6mm/10%

Well Optimization Could add up to 2,000 Boe/d for $2mm, pending further review

Recompletions 5,000 - 8,000 BOE/d risked potential futures adds Drilling: oil and gas wells >>70,000 BOE/d (net) of new drills have been identified on bypass pay Many locations will qualify for flow-through expenditures Anticipate focusing on liquids-rich gas, Narraway oil, and other oil pools Initiate EOR schemes for existing oil pools

Four Potential Divestitures (2 in Alberta, 2 in BC), Pending Technical Review Alberta Assets are within the deep basin and will likely be in high demand In total 5,590 BOE/d, $5-15mm proceeds

21

22

“Best in class” technical expertise aligned with Foothills focus Proven technical team that have successfully focused [exclusively] on Foothills exploration and

development. Strong Board with a diversified skillset to support management in growing Ikkuma.

Sound balance sheet management will allow Ikkuma to grow prudently Termed out debt with undrawn reserve based credit facility, expected to increase to $40 million

following completion of the acquisition.

Self-funded growth company Large contiguous land base with multi-stack pay. Significant light oil pool discovery: 485 MMBoe WI PIPP. Low-cost optimization and light oil exploration and development opportunities funded through

free cash flow. 11% base decline highlights lack of drill-bit capital spending in an opportunity rich fairway. Extensive ownership of underutilized infrastructure .

Compelling valuation should drive share price growth ~$3,000 boe/d, 2.45X estimated proforma cash flow, $271.8MM PDP & $372MM TPP value (NPV

10% BT)(1).

(1) See page 8 form more detailed listings.

23

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

LEGAL COUNSEL

Borden Ladner Gervais LLP

TRANSFER AGENT

Alliance Trust Company

RESERVE & RESOURCE EVALUATORSDeloitte LLP

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

DIRECTORS

Dave Anderson

Bob Dales

Tim de Freitas

Dorothy Else

Charle Gamba

Bill Guinan

Mike Kohut

24

25

(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.

(4) Two reserve evaluations were prepared for the Central Alberta Foothills Assets (Ansell/Ram) with effective dates of June 30, 2017, and Dec 31, 2016. The Dec 31, 2016 Deloitte Report is a rollback of reserves evaluation with a June 30, 2017 effective date; with the same effective date at YE2016, reserve categories and values are added.

AECO Edmont Lt AECO Edmont Lt AECO Edmont Lt

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

2017 2.58$ 64.85$ 2.79$ 69.33$ 2.75$ 63.26$

2018 2.55$ 65.80$ 2.93$ 72.26$ 3.27$ 74.51$

2019 2.80$ 67.95$ 3.05$ 75.00$ 3.22$ 78.24$

2020 3.00$ 69.15$ 3.22$ 76.63$ 3.91$ 80.64$

2021 3.20$ 71.75$ 3.39$ 78.82$ 4.00$ 82.25$

2022 3.35$ 77.65$ 3.58$ 82.45$ 4.10$ 83.90$

2023 3.60$ 77.65$ 3.76$ 65.88$ 4.19$ 85.58$

2024 3.85$ 77.65$ 3.95$ 89.41$ 4.29$ 87.29$

2025 4.20$ 77.65$ 4.03$ 92.94$ 4.40$ 89.03$

2026 4.45$ 77.65$ 4.11$ 95.61$ 4.50$ 90.81$

PRICE FILES

Deloitte (Jan 1, 2016)

Year

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

Gas Production from Devonian formations (Pine Point, Jean Marie)

Q3 2017 production was approximately 5,300 BOE/d

4,400 BOE/d is currently shut in due to facilities shutdown

Presently evaluating possibility of commencing production into AECO sales line, pending capital investment and anticipated 20-50% OPEX reduction

26

0

5,000

10,000

15,000

20,000

25,000

30,000

Jun-

04

Jan-

05

Aug-

05

Mar

-06

Oct

-06

May

-07

Dec-

07

Jul-0

8

Feb-

09

Sep-

09

Apr-

10

Nov

-10

Jun-

11

Jan-

12

Aug-

12

Mar

-13

Oct

-13

May

-14

Dec-

14

Jul-1

5

Feb-

16

Sep-

16

Apr-

17

Nov

-17

Jun-

18

Jan-

19

Aug-

19

Mar

-20

Oct

-20

May

-21

Dec-

21

Mcf

/d

Date

Sierra-Ekwan(Gross Gas Production)

Actual Forecast

8% Decline

Foothills Cardium (Stolberg), the most profitable Cardium play in the basin.

27

Lochend (78% liq)

Garrington (85% liq)

Ferrier (38% liq)

Willesden Grn (45% liq)

Wilson Crk (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) 174 143 291 229 152 128 127 141 191 112 206 305IP 90% Liquids 78% 85% 38% 45% 71% 82% 85% 82% 44% 78% 45% 87%EUR (mboe) 199 173 381 323 159 174 194 178 213 250 312 424EUR % 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 $3.6Sample Wells 138 436 163 487 180 537 137 801 80 61 91 35NPV10* ($mm) $(0.1) $0.2 $1.5 $0.8 $0.0 $0.7 $0.9 $0.7 $0.0 $1.4 $0.3 $2.3IRR 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 $31Top Operators by Hz. Prod'n:

Pengrowth Pengrowth Orlen Bellatrix Tamarack Bonterra ARC Lightstream Long Run TORC Long Run ManitokLightstream 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.

28

> 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

29

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.

30

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

31

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.

Future operations

Further pressure work required in order to understand future completion designs.

Recompletions on newly acquired vertical wells will confirm pressure assumptions and direct future drilling opportunities

Depending on results of this work (Q1-Q2, 2018), a 2-4 well program will be initiated in Q2 or Q3, 2018, subject to budgetary approval

1400

1420

1440

1460

1480

1500

1520

1400

1420

1440

1460

1480

1500

1520

Density PorosityGamma Ray

Dep

th (m

)

Cardium

32

Brown Creek oil and gas pools (Cardium)

Most gas currently producing from deeper formations (Turner Valley)

Multiple thrust sheets containing bypass Mannville (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, Falher, Wilrich, Gething, 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