A Growth-Oriented Oil and Gas Companyin the Alberta and BC Foothills

Certain information with respect to Ikkuma Resources (“Ikkuma” or the “Corporation”) included in this presentation constitutes forward-lookinginformation under applicable securities legislation. Forward-looking information typically contains statements with words such as “anticipate”, “believe”,“expect”, “plan”, “intend”, “estimate”, “propose”, “project” or similar words suggesting future outcomes or statements regarding an outlook. Forward-looking information in this presentation may include, but is not limited to, potential flow rate from recently recompleted wells, the number of de-risked,low risk drilling locations, the number of offset locations, the timing of future drilling operations, the potential future OPEX in the $4.25 - $4.50 range,expected future well flow rates, the types of expenditures for the remainder of 2016, the estimated economic outcome of new gas wells and newrecompletions, and Ikkuma’s commitment to spend within 2016 cash flow.Forward-looking information is based on a number of factors and assumptions which have been used to develop such information but which may proveto be incorrect. Although management believes that the expectations reflected in its forward-looking information are reasonable, undue reliance shouldnot be placed on forward-looking information because there can be no assurance that such expectations will prove to be correct. In addition to otherfactors and assumptions which may be identified in this presentation, assumptions have been made regarding and are implicit in, among other things,expectations and assumptions concerning the performance of existing wells and success obtained in drilling new wells, anticipated expenses, cash flowand capital expenditures and the application of regulatory and royalty regimes. Readers are cautioned that the foregoing list is not exhaustive of allfactors 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 resultscould differ materially from those currently anticipated due to a number of factors and risks. These include, but are not limited to, risks associated withthe oil and gas industry in general (e.g., operational risks in development, exploration and production; delays or changes in plans with respect toexploration or development projects or capital expenditures; the uncertainty of reserve estimates; the uncertainty of estimates and projections relating toproduction, costs and expenses, and health, safety and environmental risks), commodity price and exchange rate fluctuations and uncertainties resultingfrom potential delays or changes in plans with respect to exploration or development projects or capital expenditures.Forward-looking information is based on current expectations, estimates and projections that involve a number of risks and uncertainties which couldcause actual results to differ materially from those anticipated by the proposed management and described in the forward-looking information. Theforward-looking information contained in this presentation is made as of the date hereof and management undertakes no obligation to update publiclyor revise any forward-looking information, whether as a result of new information, future events or otherwise, unless required by applicable securitieslaws. The forward-looking information contained in this presentation is expressly qualified by this cautionary statement.This presentation contains the term “netbacks” which is not a term recognized under IFRS. This measure is used by management to help evaluatecorporate performance as well as to evaluate acquisitions. Management considers netbacks as a key measure as it demonstrates its profitability relativeto current commodity prices. Operating net backs are calculated by taking total revenues (net of realized hedging gains or losses) and subtractingroyalties, operating expenses and transportations costs on a per BOE basis.

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 barrels of oil equivalence is based on an energy equivalency conversion method primarily applicable at the burner tip anddoes not represent a value equivalency at the wellhead. All BOE conversions in the report are derived from converting gas to oil in the ratio mix of sixthousand cubic feet of gas to one barrel of oil.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/dmeans million cubic feet per day; (v) bbls means barrels; (vi) mbbls means thousand barrels; (vii) mmbbls means million barrels; (viii) bbls/d means barrelsper day; (ix) bcf means billion cubic feet; (x) mboe means thousand barrels of oil equivalent; (xi) mmboe means million barrels of oil equivalent and (xii)boe/d means barrels of oil equivalent per day.

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Strategy High growth, low decline , gas-weighted, oil upside, in conventional bypassed reservoirs

Focus Alberta and BC Foothills

Symbol TSX-V: "IKM"

Basic / F.D. Shares Outstanding 94.2 mm / 98.4 mm

Market Capitalization: diluted/undiluted (1) ~$71 mm / ~$74 mm

Credit Facility $40 mm

Current Production (2) ~5,000-7,000 boe/d (98% gas-weighted)

2P Reserves (mmboe / NPV 10%) (3) 27.5 mmboe / $202 mm

Infrastructure 560 km pipelines; 9 processing facilities (ownership in 3 gas plants); est. value of $250 – 300 mm

Current Net Undeveloped / Net Developed Land ~159,917 / 63,947 acres

Tax Pools ~$200 mm

2P NPV10% estimate, undiluted/diluted (3) $2.15/$2.06

PDP NPV10% estimate, undiluted/diluted (3) $1.24/$1.18

Undiluted market Cap/NPV10% (PDP/2P) (1) 60% /35%

Insider Ownership, undiluted/diluted(4) ~16%/19%

(1) Based on $0.75/sh.(2) Present variance is due to curtailments, shut-in production (in some cases for economic reasons). Approximately 1,000 boe/d, sour gas, remains shut in for economic reasons. (3) Reserves evaluation from the 2015YE Sproule Report; reserves are outlined later in this presentation.(4) Includes Royal Capital Management Corp.

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Defensive Strategy in Persistent Low Commodity Price Environment Core asset with 10-15% annual decline.

Sound balance sheet.

Recompletion operations with demonstrably quick payout underpins reserves/production growth.

Approximately 5,100 Boe/d (2016) and 3,800 Boe/d (2017) hedged at $3.06/Mcf and $2.86/Mcf (AECO).

Unique Skill Set and Growth Potential in an Area with Prolific Conventional Reservoirs Assembled a world class technical team with 150+ years of combined foothills operational experience.

Identified a multiyear drilling program and significantly de-risked part of this program, with results to date.

Identified 30 drill locations with potentially more than 30 MBoe/d unrisked adds.

YTD OPEX is $8 - $9/Boe and future reductions are anticipated.

Sweet gas redirect within existing infrastructure will further decrease OPEX.

Undervalued Trading at 60% of PDP(1) and 35% of 2P(1) value (based on $0 value on midstream assets with an expected

replacement value of $250-350 mm). Estimated midstream value is ~8X present market cap.(1)

Top quartile cost efficiencies amongst a select list of Canadian producers.

Growth Existing production capacity is approximately 7,800 - 8,000 boe/d.

Emerging oil play could be transformational and provide significant liquids growth.

(1) See later slide for a summary of present reserves; market cap value at $0.75/share.

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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, incl. 4 gas plants, ~560 km pipelines.

Highly focused with numerous undeveloped stacked conventional structured reservoirs.

32%

20%

12%

11%

7%

2%

N.E. limit of Foothills Play

(1) Approximately 16% of total production is in southern Alberta Foothills

Area production, as a percent of total (1)

IKM Trunk Pipeline

In the southern part of asset base alone, there is at least 100 MMcf/d ownership gas processing and transporting capability that could bring OPEX to the $4.25-$4.50/BOE range, thus becoming one of the lowest cost producers in the basin.

Potentially lower OPEX and low decline conventional reservoirs provides long term value in a volatile commodity environment. 560 km of operated pipelines gives Ikkuma several options to deliver gas to multiple processing points.

Ownership in 3 gas plants and optionality in at least 3 additional, underutilized gas processing facilities.

With increasing production, trunk line volumes may be managed more effectively.

EdsonHorseCopton (70% WI)Leland (39% WI)Unused capacity ~120 MMcf/d

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

IKM Pipeline Gas re-direct and sour gas shut-in will significantly reduce OPEX

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Source: Averaged interpreted base declines of First Energy (July 2015), TD (Aug 2015), and Scotia (May 2015)

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.

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CVE

PNE

IKM

NBZ PG

FGX

OSG

YHS

EAE

TTO

GAR

XM

PGPW

TSP

E REBN

EYO MEI

LRE

BXO

PMT

TVL

BIR

TVE

DEE

TET

KCK

BTE

LEG

PEY

POU CR

TOU

CQE

% B

ase

Decl

ine

CORPORATE PRODUCTION BASE DECLINE

IKM

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Source: Beacon Securities, September, 2016

IKM

IKM

$/bo

e

9

Source: Data from Acumen, September, 2016

IKM

IKM

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Curr

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Cumulative BOE to date

IKM 13-26-58-7W6

Best-in-class recompletion results as compared to NBF top wells for January 2016.

Proven offsets to drill when prices recover.

About 6 offsetting locations that are 100% owned by IKM.

Excellent returns, even at low commodity prices.

Source: National Bank Financial March 9, 2016 “Industry Comment.”Public (GeoScout) data added for 13-26-58-7W6.

Operator Well Date Boe Boed/d

Crescent Point 08-32-029-21W3/0 2015-07-08 8,612 41

Crescent Point 10-28-008-05W2/0 2015-07-11 8,856 43

Crescent Point 08-32-029-21W3/0 2015-05-27 9,885 40

Tourmaline 14-11-056-27W5/0 2015-04-02 23,861 78

Shell 06-16-063-20W5/0 2015-11-18 25,660 342

ConocoPhillips 13-18-052-14W5/0 2015-07-31 35,895 194

Cdn Nat 09-16-075-11W6/0 2015-03-20 51,961 163

Shell 08-25-040-08W5/0 2015-06-01 72,974 298

Encana 02-31-063-21W5/0 2015-06-21 84,987 378

Seven Generations 10-10-064-05W6/0 2015-04-06 101,919 339

Encana 07-16-063-21W5/0 2015-06-22 118,920 531

Seven Generations 04-35-063-05W6/0 2015-05-31 160,698 653

IKM • 13-26-58-7W6 2015-09-01 183,000 1666

Peyto 16-33-043-12W5/0 2015-03-20 200,020 629

Westbrick 15-19-045-11W5/0 2015-03-24 289,506 922

Cdn Nat 15-28-053-25W5/0 2015-04-01 323,726 1,058

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Recently completed one of the most prolific unstimulated wells in western Canada in recent years.

Recompletion and tie in Capital of $1,200 k.

Tested at 20 MMcf/d (3,435 boed/d) and potential to flow at more than 30 MMcf/d (5,167 Boe/d) at pipeline pressure (gross, 50% net APO). Flow rates during test were constrained by surface equipment.

Each recompletion identified/de-risked ~6 additional drilling locations (12 wells de-risked total).

Presently flowing inline at approximately 4 - 6 MMcf/d.

$-

$2,000

$4,000

$6,000

$8,000

$10,000

$12,000

$- $0.50 $1.00 $1.50 $2.00 $2.50 $3.00 $3.50 $4.00

NPV

10%

($M

)

$/AECO-flattened prices: Q1, 2016, effective date

$0.96/Mcf$0.89/Mcf

RECOMPLETION INPUTSP70 P90

IP (MMcf/d) 12.00 9.00 Production (Bcf) 11.00 8.00 Recomplete/equip CAPEX ($MM)* $1.20 $1.20Payout (years) 0.2 0.3NPV10% ($M) at $3.00 flat price $9,212.94 $6,682.33

P70

P90

*Risked CAPEX (costs could be 30% less than listed)

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Recompletions of existing well bores. These wells targeted deeper structural features and shallower targets not necessarily in ideal structural positions.

Despite these constraints, early recompletion results yielded greater than 2,400 boe/d from unstimulated reservoirs.

Offsetting sections are 100% owned by IKM; potentially 12 offset locations with 100% ownership.

Reasonable returns, even at a low commodity prices.

$-

$1,000

$2,000

$3,000

$4,000

$5,000

$6,000

$7,000

$- $0.50 $1.00 $1.50 $2.00 $2.50 $3.00 $3.50 $4.00

NPV

10%

($M

)

$/AECO-flattened prices: Q1, 2016, effective date

$2.50$1.95

NEW OFFSET DRILL INPUTSP70 P90

IP (MMcf/d) 12.00 9.00Production (Bcf) 11.00 8.00Drill/equip CAPEX ($MM) $8.70 $8.70Payout (years) 1.8 1.2NPV10% ($M) at $3.00-flat price $4,850.70 $1,327.70

P70

P90

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14 Locations : North(2 Cadotte, 9 Falher, 3 Nik)

17 Locations : North & Central(8 Cardium, 4 Falher, 5 Dunvegan)

7 Locations : South(3 Dunvegan, 3 Falher, 1 Nik)

12-17 Recompletions within Core Asset Base(incl. Cardium, Cadotte, Falher, Dunvegan, Gething Nik)

Opportunities Identified to Date

38 development locations (>30 Mboe/d potential).

12-17 recompletions (>5 Mboe/d potential).

Regional hydrocarbon charge.

Light oil and natural gas in a naturally fractured low permeability reservoir.

Vertical wells that have produced more than 30 Mbbl and IKM recompletions have confirmed widespread 49-510

API oil.

Reasonable wells costs ($3 – $4.5 mm).

More than 100 locations have been identified so far.

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IP (b

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pea

k pr

od.)

IRR (%)

IRR (ARF vs MRF)

IRR (ARF)IRR (MRF)

TARGET RESERVOIR

Future Operations

Q3-Q4, 2016: 2016 Fracture stimulate existing HZ well bore drill nearby HZ well on new fault/fold structure Testing in late Q3, early Q4

2017: Drill additional 5-10 wells offsetting first well tests; test

additional hydrocarbon charged fault/fold structures

Excellent IRR and payout at assumed prices.

Improved IRR under new royalty framework (MRF).

Why own IKM stock?

1. Unique business Experienced technical team with highly specialized engineering and geoscience skills in an area with

little competition. Underexploited part of the basin: prolific conventional reservoirs proven to exist in bypass zones, based

on Ikkuma’s recompletion results to date. Asset and land acquisitions have little competition, thus generating better full-cycle economics; YTD

costs for acquiring crown land are $5/acre.

2. Undervalued Leading G&A efficiencies. OPEX decreasing: low cost producer. Low corporate decline, generates exceptional production growth capital efficiency. Well hedged through 2016 and 2017.

3. Clear Path to Growth Exceptional results to date: some of the best gas wells in Western Canada. Multiyear drilling inventory (oil and gas) that has been de-risked with current recompletion operations. Recompletions extremely economic at very low gas prices; 10 well recompletion inventory to be

executed over the next 12 to 18 months. Emerging oil play that could be very material, once de-risked.

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ANALYST COVERAGE

TD Securities Juan Jarrah

Desjardins Jamie Kubik

Clarus Securities Rob Pare

Haywood Securities Darrell Bishop

First Energy Cody Kwong

PI Financial

Acumen Capital

Beacon Securities

Brian Purdy

Trevor Reynolds

Kirk Wilson

MANAGEMENT

Tim de FreitasPresident & CEO

Dorothy Else Executive VP

Carrie YuillVP Finance & CFO

Greg Feltham VP Exploration

Kavanagh Mannas VP Operations

Yvonne McLeod Senior VP Engineering

Rich RoweVP Land

BANKS

The Toronto-Dominion Bank

ATB

AUDITOR

KPMG LLP

LEGAL COUNSEL

Borden Ladner Gervais LLP

TRANSFER AGENT

Alliance Trust Company

RESERVE EVALUATORS

Sproule and Associates Ltd.

BOARD OF DIRECTORS

Robert Dales (Chairman)

Dave Anderson

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

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Reserves Category NPV 10% (M$) Oil (Mbbl) Liquids

(Mbbl)Gas

(MMcf) MBOE

Developed Producing $116,426 1.0 432.0 83,962 14,427

Developed Non-Producing $ 10,110 - 6.6 8,043 1,347

Undeveloped $ 19,554 - 7.2 25,493 4,256

Total Proved $146,090 1.0 446.0 117,498 20,030

Probable $ 56,315 0.5 71.6 44,635 7,511

Total proved plus probable $202,406 1.5 517.6 162,133 27,541

Based on Dec 2015 Consensus Price Forecast (Sproule, McDaniel, GLJ)

Year

Canadian Lt Sweet

Crude 40°API ($C/Bbl)

Western Canada

Select 20.5°API ($C/Bbl)

Alberta AECO-C ($C/MMBtu)

Edmonton Propane ($C/Bbl)

Edmonton butane

($C/Bbl)

Edmonton Pentane

plus ($C/Bbl)

Exchange Rate

($US/$C)

2016 $ 55.89 $ 44.64 $ 2.57 $ 9.76 $ 38.73 $ 60.16 $ 0.74

2017 $ 66.47 $ 54.52 $ 3.14 $ 15.88 $ 46.91 $ 70.95 $ 0.77

2018 $ 73.21 $ 60.32 $ 3.47 $ 24.09 $ 52.58 $ 78.05 $ 0.80

2019 $ 81.35 $ 67.42 $ 3.80 $ 30.49 $ 59.42 $ 86.58 $ 0.82

2020 $ 84.57 $ 70.47 $ 3.99 $ 33.69 $ 62.81 $ 90.00 $ 0.83

2021 $ 87.88 $ 73.50 $ 4.13 $ 34.95 $ 65.25 $ 93.46 $ 0.84

2022 $ 92.01 $ 77.25 $ 4.30 $ 36.45 $ 68.33 $ 97.79 $ 0.84

2023 $ 96.24 $ 80.95 $ 4.48 $ 38.06 $ 71.46 $ 102.23 $ 0.84

2024 $ 98.17 $ 83.09 $ 4.60 $ 38.79 $ 72.90 $ 104.29 $ 0.84

2025 $ 99.94 $ 84.56 $ 4.70 $ 39.50 $ 74.22 $ 106.16 $ 0.84

2026 $ 101.79 $ 86.16 $ 4.79 $ 40.23 $ 75.58 $ 108.12 $ 0.84

2027+ prices escalate at 1.5% thereafter

NET ASSET VALUE PER SHARE

10% NPV of 2P P&NG reserves, before tax ($000's) $ 202,406

Undeveloped land (1) ($000's) $ 15,337

2015 YE Estimated Net Debt (Unaudited) ($000's) $ (32,890)

Net asset value ($000's) $ 184,853

Undiluted common shares outstanding (000's) $ 80,159

Diluted common shares outstanding (000's) $ 84,336

Net asset value per share - undiluted $ 2.31

Net asset value per share -fully diluted $ 2.19

(1) Estimated at $110/acre

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CARDIUM PLAY BOOK(1)

IP90 (boe/d) EUR (mboe) IRR Mostly Oil Mostly Gas

Foothills delivers highest rate oil wells and leading economics in the basin.

Payout in 0.6 – 2 years at C$40 – C$80/bbl.

Emerging oil play at IKM has the potential to deliver similar returns.

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.

STOLBERG(1,2) IP WELL POPULATION

CARDIUM DATA BY AREA(1)

(1) TD Industry Note, June 2016.(2) Sample population includes wells that penetrated Cordel oil pool in 2012-2013, which lowers Stolberg average EUR and IP.

30 X multiple of vertical vs. horizontal.

Produced >200 mbbls 52 API oil and 1Bcf in 20 months.

This well was not stimulated, and free-flowed to surface for all of its production history.

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An example of a large resource captured through horizontal drilling in shallow bypass reservoirs:

Discovery vertical well (1997), 8-31-42-15w5.

IP 24-30 bbls/d.

Produced 30 mbbls.

Source: Geoscout

Source: Geoscout

IP: 24-30 bbl/d

Source: Geoscout

600 bbl/d

400 bbl/d

200 bbl/d

IP: ~1,000 bbl/d

Source: Geoscout

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Vertical - HZ Well Multiplier: the Cardium Formation in Elmworth / Wapiti has the most similar reservoir characteristics, based on logs. On average, horizontal wells in Wapiti benefit from a 9.3x increase on IP, 6.8x increase on EUR when compared to near offset vertical wells.

The average of the two Cardium wells within the foothills trend was used for an expected vertical IP of 149 bopd. Applying the Wapiti HWM to this number yields an expected horizontal IP of 1378 bopd and 212,215 bbls EUR.

HEAVILY RISKED well IP of 250-400 bopd were used for modelling.

Note: Stolberg average well multiplier is higher due to the natural fracture system in place (unstimulated vs stimulated).

Peak Prod. EUR

Peak Prod. Rate EUR

bbl/d bbl bbl/d bblMean 1 well 36 17,000 224.91 81,597 S-Mean 221.88 94,221 Median 191.74 65,378 Count 55.00 55 Std. Dev. 190.55 58,055 r² 0.93 0.93

Dist Peak (bbl/d) EUR (Mbb)Min 31.7 1,931 P99 29.8 5,435 P90 65.2 15,862 P80 90.8 24,901

P75 102.9 29,555 P70 115.2 34,471 P60 141.1 45,512 P50 170.7 59,009 P40 206.5 76,510 P30 253.1 101,017 P25 283.2 117,819.6 P20 321.1 139,838.9 P10 446.8 219,529.8 P1 978.8 640,703.5 Max 1,200.7 299,411.9

Elm/Wapiti South-OIL (all wells outside Wapiti Pool)Vert (one well), offset pool is conv. Wapiti HZ

Peak Prod. EUR

Peak Prod. Rate EUR

bbl/d bbl bbl/d bblMean 1 well 36 17,000 324.22 109,072 S-Mean 333.96 116,376 Median 284.01 95,706 Count 25.00 25 Std. Dev. 228.99 69,304 r² 0.90 0.94

Peak (bbl/d) EUR (Mbb)Dist 31.74 4,909 Min 47.4 14,597 P99 101.8 32,742 P90 140.5 46,009 P80 158.8 52,356

P75 177.2 58,798 P70 216.1 72,508 P60 260.1 88,198 P50 313.1 107,284 P40 381.8 132,299 P30 426.2 148,579 P25 481.6 169,075.1 P20 664.6 237,580.3 P10 1,427.9 532,914.9 P1 1,200.7 299,411.9 Max 1,200.7 299,411.9

Elm/Wapiti-Oil (near offset to vertical wellVert (one well), offset pool is conv. Wapit HZ

IP-X EUR-XElm/Wapiti South-OIL (all wells outside Wapiti Pool) 6.2 5.5 Elm/Wapiti (near offsets) 9.3 6.8 Stolberg 15.4 6.2 Harme-Oil (32-3) 12.4 1.9 Kaybob (60-20-22) 6.3 17.1 Pembina (45-11,12) gasy 5.7 0.7

Vertcal Well #1 222 31,000 Vertcal Well #2 75 n/a

149 31,000 Use Elm/Wapiti near offset multlier 1,378 212,215

IKM Alberta Foothills

Summary (HZ Multiplier)