AGROWTH

ORIENTED

OIL & GAS PRODUCERFOOTH ILLS

2

(1) As at March 31, 2018.(2) Excludes sulphur production with annual sulphur revenue in excess of $8 million.(3) As at December 31, 2017 based on the Deloitte Report(4) Estimated net replacement value.

Market Capitalization (1) $31 MillionTerm Debt (1) (7.25% coupon, matures March 2022) $45 MillionNet Bank Debt (1) (bank debt and working capital deficiency) $16 MillionEnterprise Value $92 Million

Basic Shares Outstanding (1) 109 MillionDiluted Shares Outstanding (1) 127 MillionSyndicated Bank Credit Facility (1) $25 Million

2017 Average Daily Production 6,366 BOE/dQ1 2018 Average Daily Production (2) 19,292 BOE/d

Proved Developed Producing (“PDP”) Reserves (3) 57 MMboePDP Reserves Value (3) $301 MillionProved and Probable (“P&P”) Reserves (3) 107 MMboeP&P Reserves Value (3) $488 MillionBase Production Decline Rate 10%Net Undeveloped Land ~400,000 AcresValue of ~1,800 km of Pipelines and Processing Facilities (4) ~$600 Million

Accomplishments to Date 2018 Objectives

A team with a long history of expertise in Foothills oil & gas operations

Operating cost reduction of up to 20% per BOE increases operating netbacks and NPV values

Increased oil and gas production to current levels of ~19,000 BOE/d with a 10% decline rate

Well optimization will be a focus and production declines could be replenished at minimal costs

Increased PDP reserves in 2017 by 316% to 56.8 MMBOE and 2P reserves by 287% to 106.6 MMBOE

Divestitures of non-core assets and redeploy proceeds to high-value opportunities within a prudent finance strategy

Expanded an already large inventory of crude oil drilling locations in light oil pools throughout the foothills

Capital expenditure program for 2018 focused on $12 million flow through obligation on multi-zone drilling opportunities

Access to extensive underutilized infrastructure with no egress issues

Crude oil drilling locations, and recompletion and bypass pay opportunities will be further identified

Prudently financed acquisitions and drilling and completions activity in a very difficult energy sector over the past three years

To expand the risk management program beyondthe current hedge position (16% of estimated production for the remainder of 2018 at a price of $2.60/GJ)

3

0

30

60

90

120

150

180

0

4,000

8,000

12,000

16,000

20,000

2014 2015 2016 2017 2018 [E]

Productio

n (BOE/d

) / Millio

n SharesAve

rage

Pro

duct

ion B

OE/

d

Average Production BOE/D Production (BOE/D) / Million Shares

4

16,500-17,500

A near three fold increase in production from 2017 to 2018 in a challenging pricing environment

-

0.2

0.4

0.6

0.8

-

30,000

60,000

90,000

120,000

2014YE 2015YE 2016YE 2017YE

BO

E/share

Res

erve

s (M

BO

E)

PDP (MBOE) TP (MBOE) TPP (MBOE) TPP (BOE/share)

5

317% increase in Proved Reserves and

300% increase in PDP Reserves in 2017

FD&A and Recycle Ratio ($/BOE)(2) Proved Proved & Probable

FD&A ($/BOE) (2) $1.99 $1.50

Recycle Ratio (3) 2.5x 3.4x

6

(1) Reserves are per the reports prepared by Deliotte LLP for 2017 and Sproule Associates Limited for 2016. Reserve volumes include Company gross working interest share of remaining reserves, as determined in accordance with NI 51-101.

(2) Including change in future development capital, decommissioning obligations on acquisitions and proceeds from sale of assets.(3) Recycle Ratio is calculated by dividing operating netbacks (2017 - $5.07; 2016 - $6.96) by FD&A cost.

Reserves (MBOE) (1) PDP Proved Proved & Probable

As at December 31, 2017 56,809 79,634 106,637

As at December 31, 2016 13,642 19,931 27,539

Percent Increase 316 % 300 % 287 %

Reserves (NPV 10 - $MM) (1) PDP Proved Proved & Probable

As at December 31, 2017 $301.2 $375.5 $488.2

As at December 31, 2016 $103.5 $131.8 $190.0

Percent Increase 191 % 185 % 157 %

Bestin

Class

7

$23,578 $22,746

$16,119

$5,447

0

5,000

10,000

15,000

20,000

25,000

$0

$5,000

$10,000

$15,000

$20,000

$25,000

2014 2015 2016 2017

Exit Pro

ductio

n (B

OE/d

)Cap

ital

Eff

icie

nci

es ($/

BO

E/d)

Capital Efficiencies ($/BOE/D)

Exit Production (BOE/D)

8

Source: TD Securities

$92

56,809

0

25,000

50,000

75,000

100,000

$0

$500

$1,000

$1,500

$2,000

IKM PNE SRX BXE CR NVA KEL AAV

PDP M

BOEEV

($M

M)

2017YE PDP, BOE & Enterprise Value "EV" EV ($MM) PDP (MBOE) Gas Weighted Companies

$92

$301

$0

$500

$1,000

$1,500

$0

$500

$1,000

$1,500

IKM PNE SRX BXE CR NVA KEL AAV

PDP, N

PV10%

($M)

EV ($M

M)

2017YE PDP, NPV10% & EV EV ($MM) PDP NPV10% ($MM)

9

0%

10%

20%

30%

40%

50%

60%

70%

80%

90%

100%

$-

$5.00

$10.00

$15.00

$20.00

$25.00

IKM PONY PNE AAV PEY BIR CR BXE BNP NVA KEL PRQ

% G

AS

Valu

e/Sh

are

Reserve Evaluator $/Share, Debt Adjusted, Gas Weighted Producers

NPV10%PDP/share NPV10% 1P/share NPV10% 2P/share share price %GAS

IKM

Source: Altacorp/TD, Spring 2018

Net debt adjusted per share value, based on year end reserves.

Year end evaluation on various evaluator price decks.

IKM year reserves were completed by Deloitte using a consensus price deck of 4 evaluators.

0

10,000

20,000

30,000

40,000

50,000

60,000

70,000

80,000

90,000

100,000

0

5,000

10,000

15,000

20,000

25,000

30,000

Jan-

06Ap

r-06

Jul-0

6O

ct-0

6Ja

n-07

Apr-

07Ju

l-07

Oct

-07

Jan-

08Ap

r-08

Jul-0

8O

ct-0

8Ja

n-09

Apr-

09Ju

l-09

Oct

-09

Jan-

10Ap

r-10

Jul-1

0O

ct-1

0Ja

n-11

Apr-

11Ju

l-11

Oct

-11

Jan-

12Ap

r-12

Jul-1

2O

ct-1

2Ja

n-13

Apr-

13Ju

l-13

Oct

-13

Jan-

14Ap

r-14

Jul-1

4O

ct-1

4Ja

n-15

Apr-

15Ju

l-15

Oct

-15

Jan-

16Ap

r-16

Jul-1

6O

ct-1

6

US

TTO

TAL

GAS

PRO

DUCT

ION

(MM

CF/D

)

REGA

ION

AL G

AS P

RODU

CTIO

N (M

MCF

/D)

US Gas production

GOM

Pennsyl.

Texas

TTL US

10

TD, May 2018

Record storage 17/18 gas withdrawal: unprecedented April storage withdrawal (first time in history with 3 weeks of gas withdrawal); record 1 week withdrawal (359 Bcf)

This was deemed in “normal winter”, based on HDD” Alberta was slightly below normal and saw strong gas withdrawals

as well But US production remains strong (~80 Bcf/d), with most supply

coming from Marcellus (pipeline “de-bottleneck” in Midwest US); weakening of Texas production

ARM, June 4, 2018

Improving NYMEX forward curve: Commodity traders anticipating under-filled gas storage at start of heating season; backwardation reflects view that gap will be filled by gas from oil and other shale gas plays. Demand shows continuous improvement.

Shell outlook, Spring 2018

Export of US Gas south to Mexico was 4.53 Bcf/d Wednesday (May 29th, 2018), surpassing a previous record set in March, an increase in 36% in a week (TD May, 2018); few months ago the EIA was predicting declining pipeline export gas volumes

LNG demand continues to surge outstripping supply for the foreseeable future. EIA indicates decreasing Canadian imports.

Will Canada get LNG? Will we be able to follow through on allowing permitting and construction? Shell seems to have some momentum.

Weather demand for 2018/19? Cooling this summer?

Coal to gas switching; clean energy, etc., pushing demand further

Driving Canadian Shell FID?

?

11

12

In Q1 AECO oversupply was bailed out and demand remains strong (Q1 exports high, and 17/18 cold winter depleted storage) 0.2 Bcf/d undersupply for 2018, taking gas off TCPL export pipelines (TPH(1), March, 2018) Cannot fill storage entering heating season with deficit; line maintenance results in underfilled storage TPH (March, 2018) suggests likelihood of near term strength in AECO pricing versus US Midwest Hubs. “…C$0.50/mcf upside to Q3 and Q4 strip, to C$1.85/mcf and C$2.35/mcf, respectively…” TPH, Spring, 2018. Gas shut-ins; CAPEX curtailments will impact supply and may not be enough to offset decline (PEY/TOU delaying CAPEX, Jupiter

shutting in 100mcf/d, Bellatrix shutting in some high-cost gas; IKM).

TPH Spring, 2018TPH Spring, 2018(1) TPH is Tudor Pickering Holt and Co.

20192019

Exports remain strong due to price differential and depleted US storage

13

High decline asset bases need backfill drilling programs; asset declines exceeding 50%. Present wedge has 39% decline Some negatives…

High supply, at least presently, with limited egress/export, particularly upstream of James River 16% of gas production from liquids weighted wells TCPL Maintenance and Cutbacks; recent US gas growth;

0%

10%

20%

30%

40%

50%

2010 2011 2012 2013 2014 2015 2016 2017 2018

WCSB Basin New Production Declines

proj

ecte

d

NBF, Spring 2018

NBF, Spring 2018

Maturing basin reservoir exploitation

14

Est. 2018 capex: gas-weighted companies $7.1 bln(1)

Western Canada Basin decline will increase each year; Basin Decline is ~3.4 Bcf/d, ~21% (NBF, April 2018; Geoscout); Assuming reasonable capital efficiencies ($15-$20,000/BOE/d) replacement of basin decline by new drilling will not be

achieved this year, particularly if most of the assumed CAPEX is directed at liquids targets(1)

(1) Altacorp data; total CAPEX is estimated at $22.5 Bln, including oil sands. The estimated $7.1 blnspend by gas-weighted companies in 2018 likely includes mostly liquids-weighted drilling targetsArc Energy Research, May 2018

ATB, May 2018

-

50,000

100,000

150,000

200,000

250,000

300,000

350,000

0 50 100 150 200 250 300 350 400 450 500

Grou

p pl

ot p

rodu

ctio

n (M

cf/d

)

months

Montney Dry Gas Producer

Well Group Decline of 58% at drilling termination

Source: Geoscout

Horizontal Drilling program termination and reserve “blowdown”

El Niño/La Niña: impacts the amount of cold weather which encompasses North America, typically stalling polar outbreaks and reducing HDD(1) and thus natural gas demand

However for winter 2018-19 predictions are unreliable at this point in time: Consensus models are indicating 50% Chance of El Niño for 2018-19

Interesting conversations about another major oceanic circulation patterns: AMO (2) and PDO(3)

PDO is entering into a negative cycle; amplifies La Niña phases, while suppressing El Niño, though there will be year-to-year variations

Also entering a “grand” solar minimum (decreased solar irradiance) coinciding with negative PDO & AMO. Tuning effect? ….Perhaps acting together to reduce winter temperatures.

15

(1) HDD – Heating Degree Days(2) AMO – Atlantic Multidecadal Oscillation (3) PDO – Pacific Decadal Oscillation

http://www.drroyspencer.com/global-warming-background-articles/the-pacific-decadal-oscillation/

Tglo

bale

mp

anom

aly

16

Reputable business reporting now questioning “climate hysteria” Investor Business Daily Scientific studies showing: The Big Chill from February 2106 to February 2018, reflecting a high degree of linkage between climate and ocean

temp., NOT CO2. Continued cooling of this magnitude will have significant short term impact on gas consumption in NA: above-

normal winters will become a rarity, and some scientists are predicting entry in to another mini ice age.

Stay tuned

2018/19 WINTER WEATHER?

AMO; PDO, El Nino

17

Edmonton

Calgary

IKM Legacy Lands

IKM Oil Pools

New IKM Lands

40 km

$600 million of underutilized infrastructure; Includes working interest ~1,800 km of pipelines, 8 major facilities and 13 minor facilities.

Added 3,090 kilometres of 2D and 100 square kilometres of 3D seismic data through recent acquisition.

Net Undeveloped Land: ~400,000 acres.

Ownership in crown lands through a 600 km subsurface play system that contains abundant bypassed conventional reservoirs.

Underexploited conventional and unconventional reservoirs with greater than 200,000 BOE/d of production adds identified.

3 Existing Light Oil Pools, numerous bypass zones; infill drilling and EOR projects on existing shallow pools

Stolberg discovered on bypass reservoir data by Ikkuma team.

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

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

18

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

Oil and gas targets identified on seismic and borehole data

0%

10%

20%

30%

40%

50%

0

100

200

300

400

Lochend(78% liq)

Garrington(85% liq)

Ferrier(38% liq)

WillesdenGrn (45%

liq)

Wilson Crk(71% liq)

EastPembina(82% liq)

CentPembina(85% liq)

W Pembina82% liq)

Edson (44%liq)

Kaybob(78% liq)

Wapiti (45%liq)

Stolberg(87% liq)

IRR (%)

IP (b

bl/d

); EU

R (M

Boe)

Cardium Play Book (TD Securities, June 2016)

IRR - GasIRR - Oil

IP BOE/dEUR (MBoe)

19

Berland E Pembina

Edson

Ferrier

Fir

Harme

Kakwa Kaybob

LochendMed River

N Pembina

Smoky N-Carrot

NW Pemb.

Rosevear

Wll Grn

Wilson Ck

Wapiti

Cordel

Stolberg

-

50

100

150

200

250

300

350

400

- 50,000 100,000 150,000 200,000 250,000 300,000

IP 3

0 (b

bl/

d)

EUR (bbl)/well/field

Peak Prod. Rate (IP30) vs EUR

IKM, well #1(1)

Anticipated Northern Alberta Foothills Trend

IKM, well #2(1)

Deep Basin Oil Pools

Foothills Oil Pools

Central Alberta Foothills Trend

(1) Narraway EUR for new wells cannot be estimated at present; Narraway well #2 remains shut-in and is likely wax plugged.

20

(1) Wilrich Deep Basin Horizontal, fields include Ansell, Brazeau, Smoky, Edson, Lambert, Edson, Kakwa, Minehead. Pine Creek, Sundance, etc. Wilrich Horizontal Foothills from the Lovett area; Mannville commingled vertical Foothills, mainly northern Alberta Foothills.

Foothills vertical and particularly horizontal wells yield superior results in the foothills when compared to equivalent deep basin reservoirs (half cycle costs assumed similar on continuous drilling and completion operations)

3-10 times multiple on IP and production/well is possible with horizontal exploration in the Foothills, due to moderate to severe fracture development

Wilrich (Mannville)

Foothills Horizontal

(n=11)

n= 454

n= 42

n= 13 n= 58

n= 78

n= 44

n= 61n= 28

n= 182

n= 200

-

2,000

4,000

6,000

8,000

10,000

12,000

14,000

- 5.00 10.00 15.00 20.00 25.00

IPea

k Rat

e, P

30 (

Mcf

/d)

Ttl Prod/well (BCF)

Well Results of Deep Basin vs Foothills Illustrating the Impact of Natural Fractures (1)

WilrichDeep Basin Horizontal

MannvilleHorizontal

?

N=42, reers to the number of wells used to calculate mean values of each data point

21

Cordel Oil Pool

Stolberg Oil Pool

Brown Creek Oil Pool

B

A

B

A

Chungo Trend

IKM Land -

10,000

20,000

30,000

HZ Vertical

Mcf

, MM

cf

Chungo Trend

Peak Prod Rate (IP30, Mcf/d/well) TTL Production (MMcf/well)

~6X IMPROVED RECOVERYFOR HZ WELLS

Oil Pool

Gas targets identified on seismic and borehole dataOil targets identified on seismic and borehole data

22

Numerous bypass pay reservoirs accessible from existing well pads and in some cases, previously drilled wells

Cardium Oil Resource audited by Deloitte is 485 BOE (WI) PIIP in northern area(1)

52,000 bbl/d unrisked (solution gas drive light oil reservoirs, 10-20% gas), mostly in Cardium Formation

Significant Montney gas present on existing land base (not included in potential production adds)

0

20,000

40,000

60,000

80,000

Ojay/Narraway Northern Central Sierra/Ekwan

UN

RIS

KED

TO

TAL

BOE/

d

AREA

Identified BOE Adds, BC & Alberta FoothillsGAS (BOE/d) OIL (BOE/d)

Total BOE/d identified to date:More than 200,000 BOE/d

~36

,000

~79

,000

~8,

000

(1) Details of the Deloitte Report were disclosed in a press release date June 5, 2017. “PIIP” Petroleum Initially In Place.

~35

,000

~45

,000

~5,

000

23

Opportunity Rich Foothills Oil and Gas Large contiguous land base Significant light crude oil potential Ongoing low-cost optimization initiatives identified to improve productivity and

reduce operating expenses 10% base decline Extensive access to underutilized infrastructure

“Best in Class” Technical Expertise Successful technical team focused on Foothills oil and gas operations Strong Board with a diversified skillset

Compelling Valuation Proved Developed Producing reserves NPV of $301 million ($2.75 per share)

Prudent Financial Management A syndicated bank credit facility of $25 million $45 million of term debt

24

ANALYST COVERAGE

Acumen Capital Trevor Reynolds

Beacon Securities Kirk Wilson

Desjardins Chris MacCulloch

GMP First Energy Cody Kwong

Haywood Securities Darrell Bishop

TD Securities Juan Jarrah

MANAGEMENT

Tim de FreitasPresident & CEO

John Van de PolSenior Vice President & CFO

Yvonne McLeod Senior VP Engineering

Greg Feltham VP Exploration

Rich RoweVP Land

Kim BendersCorporate Controller LEGAL COUNSEL

Borden Ladner Gervais LLP

TRANSFER AGENT

Alliance Trust Company

RESERVE & RESOURCE EVALUATORSDeloitte 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

AUDITORS

KPMG LLP

Certain information with respect to Ikkuma Resources Corp. (“IKM” or the “Corporation”) included in this Corporate 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 orstatements regarding an outlook. Forward-looking information in this Corporate Presentation may include, but is not limited to the achieving operating cost reductions of up to 20%/BOE and the resultingincreases to operating netbacks and NPV values, the type and timing of capital expenditures, the value of underutilized infrastructure, expectations relating to Foothills fractured fairways, the scheduling of crudeoil drilling locations and the identification and implementation of recompletion and bypass pay opportunities, the pursuit of non-core asset divestitures and redeployment of proceeds to high-value opportunitiesand the Corporation’s future operations contemplated for the remainder of 2018.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 theexpectations reflected in its forward-looking information are reasonable, undue reliance should not be placed on forward-looking information because there can be no assurance that such expectations will proveto be correct. In addition to other factors and assumptions which may be identified in this Corporate Presentation, assumptions have been made regarding and are implicit in, among other things, expectationsand 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 royaltyregimes. 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 dueto 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 changesin 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, costsand 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 ordevelopment 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 reservesand resources will be recovered. These risks and other risks 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 materially from those anticipatedby the proposed management and described in the forward-looking information. The forward-looking information contained in this Corporate Presentation is made as of the date hereof and managementundertakes 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. Theforward-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 or future orientedfinancial 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 with disclosure regarding Ikkuma’sreasonable expectations as to the anticipated results of its proposed business activities for the periods indicated. Readers are cautioned that the financial outlook 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 to similar measurespresented by other issuers. Funds flow from operations and operating netback are not recognized measures under IFRS. Management uses certain industry benchmarks such as operating netback to analyzefinancial and operating performance. This benchmark as presented does not have any standardized meaning prescribed by IFRS and therefore may not be comparable with the calculation of similar measures forother entities. Funds from operations represents cash provided by operating activities before changes in operating noncash working capital and decommissioning obligation expenditures. The Corporationconsiders it a key measure as it demonstrates the ability of the Corporation’s continuing operations to generate the funds flow necessary to fund future growth through capital investment. Operating netbackequals 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 considersoperating netback an important measure to evaluate its operational performance as it demonstrates its field level profitability relative to current commodity prices. Reconciliations of funds from operations andoperating netback to the most directly comparable measures specified under IFRS are contained in the Corporation’s management discussion and analysis, copies of which are available on SEDAR.

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 isbased 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 convertinggas 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 issignificantly 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 per day; (v) bbls meansbarrels; (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 of oil equivalent; (xi) mmboemeans million barrels of oil equivalent and (xii) boe/d means barrels of oil equivalent per day.

25

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 by management and suchlocations have not been reflected in any independent reserve or resource evaluations prepared pursuant to NI 51-101, other than the Sproule Report (as hereafter defined). Similarly, unless otherwise specified, theinformation 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 drillinglocations 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 potential drillingopportunities 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 onindustry practice and internal review. Except as set out in the Sproule 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 drilledthere 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 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 the unbooked drillinglocations 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 hasless 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 inadditional oil and gas reserves, resources or production. Of the potential 150+ drilling opportunities are proved plus probable 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 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 analyseshave 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 northern Alberta Foothillseffective May 1, 2017. See Ikkuma’s press release dated June 5, 2017 entitled “Ikkuma Resources Announces Resource Study of its Large Light Oil Discovery”.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 “Sproule Report”), prepared bySproule Associates Limited, and an independent reserves evaluation of oil and gas assets of Ikkuma effective December 31, 2017 (the “Deliotte Report”), prepared by Deliotte.

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 to the effects ofaggregation.

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 prospectiveresources) 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 anyportion 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 tovolumes 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 eachclass 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 (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 inknown 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 PIIP includes 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 technology under development, butwhich 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 prospectiveresources; the remainder is unrecoverable.

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