Corporate Presentation November 2014 TSX: YGR TSX: YGR Our job is - - PowerPoint PPT Presentation

TSX: YGR TSX: YGR

Corporate Presentation November 2014

2 TSX: YGR

• Our job is to create shareholder value
• Integrity and ethical behavior are essential to success
• Sound ethics and shareholders interests are compatible
• It is okay to be wrong: own it, accept it, learn from it
• Embrace adversity, it is a difficult business
• Diversity of skill-sets within the team are critical to success
• Loyalty, performance and achievement are recognized
• Top decile performance in all categories is the goal
• Full cycle Corporate IRR is what measures our success

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Publicly listed junior oil and gas company TSX: YGR Shares Outstanding Basic Options/Warrants (weighted average $1.87) 57.7 million 4.9 million Fully Diluted 62.6 million Insider Ownership Basic Fully Diluted 15% 21% Market Capitalization (at $1.60/share) $92 million Q3 Net Debt ($90 million in ATB credit facilities) $51 million Enterprise Value $143 million Q3/2014 net debt to annualized cash flow 1.4 : 1 Forecast Q4/2014 net debt to annualized cash flow 1.2 : 1 Future drilling locations (Cardium & Glauc) - Current 188 Gross (141 net) Proved plus Probable Reserves @ Dec 31, 2013 (Deloitte) 17.5 million boe Net Present Value @ 10% (P+P) @ Dec 31, 2013 $251 million NAV / Share (with no undeveloped land value) @ Dec 31, 2013 $4.20

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Jim Evaskevich, President & CEO

• 30+ years extensive executive experience with strong
• perations background

Lorne Simpson B.Sc., C.E.T., VP, Operations

• 30+ years experience in the industry
• Supervisor, Drilling Ops with PetroBakken Energy Ltd.
• Engineered, drilled or completed 250 HZ Cardium

wells, 200 HZ Bakken wells, 2 HZ Duvernay wells, 25 HZ Montney wells, and dozens of Blue Sky, Viking, SWS, Glauc, and Rock Creek HZ wells

Randall Faminow, VP, Land

• 30+ years of experience in all aspects of oil and gas land work,

including negotiation, acquisitions and divestments, contracts and mergers

James Glessing, CA, CFO

• 15+ years oil and gas accounting experience
• Executive and financial experience as CFO with North Peace

Energy Corp

• Controller at BlackRock Ventures,
• Canadian Natural Resources, Shell and Deloitte

Board of Directors Management Team

Neil Mackenzie

• Director of various public companies, including Canyon

Technical Services

• Currently a partner in Blackstone Fluids, an oil and gas

drilling fluids company

Ted Morton

• A former Canadian politician and cabinet minister in

the Alberta government

• Has held various positions in the Alberta Government

included Minister of Energy (2011-2012), Minister of Finance and Enterprise (2010-2011), and Minster of Sustainable Resources (2006-2010)

Gordon Bowerman

• Chairman
• President of Cove Resources Ltd
• Founder of several successful private and public oil

and gas companies

Robert Weir

• President of Weir Resource Management Ltd

Jim Evaskevich

• President and CEO of Yangarra Resources Ltd

TSX: YGR 5 24% 41% 67% 65% 12% 34% 26% 31% 0% 10% 20% 30% 40% 50% 60% 70% 80% 2010 2011 2012 2013 IRR Half Cycle IRR (1) Full Cycle IRR (2)

1. Half cycle IRR is based on actual drilling and completion costs, production to date and P+P reserves. 2. Full cycle IRR allocates all other capital costs to the wells (i.e. land, G&G, infrastructure)

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$0 $100 $200 $300 $400 $500 $600 $700 $800 2010 2011 2012 2013

Drilling cost per meter

$0 $50,000 $100,000 $150,000 $200,000 $250,000 2010 2011 2012 2013

Completion cost per stage

0.00 5.00 10.00 15.00 20.00 25.00

YGR MEI SRX RE TVE MQL RTK AEI ZAR GXE CJ Q3 2014 Operating costs/boe versus peers

Average $15.39

0.00 1.00 2.00 3.00 4.00 5.00 6.00 7.00 8.00

SRX RE YGR RTK AEI CJ GXE TVE MQL MEI ZAR Q3 2014 G&A/boe versus peers

Average $3.21

TSX: YGR 7

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TSX: YGR 9 1,000 2,000 3,000 4,000 10,000,000 20,000,000 30,000,000 40,000,000 50,000,000 2010 2011 2012 2013 2014 (est) Cashflow Production (Cashflow) (mboe)

• 0.00001

0.00002 0.00003 0.00004 0.00005 0.00006 2010 2011 2012 2013 2014

Production per share

• 0.10

0.20 0.30 0.40 0.50 0.60 0.70 0.80 2010 2011 2012 2013 2014

Cash Flow per Share

TSX: YGR 10

5,000 10,000 15,000 20,000 2010 2011 2012 2013

P+P Reserves (mboe)

Oil NGL's Natural gas 50 100 150 200 250 300 2010 2011 2012 2013

Reserve Value PV10 ($ millions)

• 298% increase in reserves since 2010 (86% per share)
• Replaced 2013 production by 614% (546% in 2012)
• Finding and development recycle ratio of 2.57 times on P+P reserves
• Finding and development costs of $14.07/boe on proved plus probable reserves
• Reserve life index of 16.0 years
• Future development costs of $125 million

50 100 150 200 250 300 2010 2011 2012 2013

Reserve Value PV10 ($ millions)

5,000 10,000 15,000 20,000 2010 2011 2012 2013

P+P Reserves (mboe)

PROB PUD PDNP PDP

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CAPEX budget for 2014 $75.0 million

• Budget focused on Central Alberta
• Includes $5 million of Duvernay spending
• Funded with cash flow and the existing credit facilities

2014 Guidance Production (boe/d) Annual Average 3,000 boe/d Cash flow from operations $40 million Year end Debt Debt to annualized Q4 cash flow $53 million 1.1 : 1 Pricing Assumptions (annual average) Crude oil – Edmonton Par $80.00/bbl Natural Gas $3.50/GJ Corporate decline assumptions 40% in year one 15% thereafter

TSX: YGR 12 TSX: YGR

Edmonton Calgary Rocky Mountain House

Central Alberta

• Interest in 140 sections of land
• 85 + horizontal wells drilled since

2010

• Focus
• Cardium and Glauc plays
• Light oil
• High netback
• Quick payouts

Red Deer Willesden Green Ferrier Pembina

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Cardium Future Drilling Locations 147 gross (107 net) Locations booked in 2013 Reserve Report 35 gross (29 net) Drill, Complete and Equip $2.7 million – $3.2 million Average: $2.9 million NPV10 ($90/bbl & $4.00/mcf) (1) $2.4 million – $4.7 million Average: $3.3 million IRR – Half cycle before tax 67% – 172% Average: 106% Payout 8 months – 16 months Average: 13 months Capital Efficiency (IP 365) $6,500 – $27,000 $14,850 Glauconite Future Drilling Locations 41 gross (34 net) Locations booked in 2013 Reserve Report 11 gross (8 net) Drill, Complete and Equip $3.0 million – $3.5 million Average: $3.3 million NPV10 ($90/bbl & $4.00/mcf) (1) $2.9 million – $6.3 million Average: $3.7 million IRR – Half cycle before tax 75% – 188% Average: 122% Payout 8 months – 13 months Average: 11 months Capital Efficiency (IP 365) $7,500 – $12,000 $10,250

Total Cardium & Glauc Locations 188 gross (141 net)

(1) Present value of future cash-flow, discounted at 10%, net of Drill, Complete and Equipping costs.

TSX: YGR 14 TSX: YGR

GAS OIL OIL

GAS

WILLESDEN GREEN CARDIUM FIELD FERRIER CARDIUM FIELD

O I L

OIL O I L H Z

GASSY GASSY

Legend Wells cardium wtr inj cardium gas cardium oil Working yangarra land Farmin land

Cardium Show Map cardium pool outlines

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CHANNEL CHANNEL HANNEL

HOADLEY HOADLEY BARRIER ISLAND BARRIER ISLAND

Glauconite Show Map Porosity Trends

Legend Wells glauc @TD glauc pens HZ glauc liquid rich gas All Glauc liquid rich gas Working Yangarra land

16 TSX: YGR

• Let industry de-risk the play
• Continue land-base to 2020 with strat test wells
• Larger players are migrating to the Duvernay which may

provide opportunities in plays like the Cardium and Glauc in Central Alberta

• Our first strat test well is planned for 2014
• Continue to collect data and further de-risk Yangarra’s

acreage

The Duvernay represents option value that is not reflected in the current share price

TSX: YGR 17

YGR Acreage

• Early production rates show initial

liquids yields up to 200 bbl/MMcf

• Duvernay operators are still

establishing Best Practices for Drilling and Completion

• Production data supports the

emergence of an economically attractive liquids fairway

• Geological parameters (mineralogy,

thickness, HC potential, TOC, fractures, brittleness, net pay, etc.) are generally known from industry activity/results, public data/analysis and YGR proprietary work

• Reservoir Characteristics evolving
• Local variations in rock

properties/well performance can be expected with further drilling

18 TSX: YGR

• Very Active Areas with

high capital investment currently by majors and large independents

• North Block primarily in

liquids window with new horizontal drilling by Vermillion/Black Swan immediately offsetting (2 miles) YGR land

• South Block surrounded

by drilling activity (Shell, Encana, Talisman, Black Swan Swan/Paramount)

YGR NORTH BLOCK YGR SOUTH BLOCK

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Yangarra Land

• Significant amounts of
• il have been produced
• ver the past 30 years

from vertical wells

• 10 to 20 million barrels
• f Original Oil in Place

(OOIP) per section

• Accumulated 45 gross

(35 net) sections

• Yangarra has 3

horizontal wells and 2 vertical wells in the SWS formation

20 TSX: YGR

Appendix

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Colorado Group 650m thick Viking Glauconitic Ellerslie Rock Creek

• Vertical production

exists in all zones

• All zones meet the

criteria for horizontal drilling

5m 30m 5m 20m 15m 10m

Duvernay Cardium Second White Specks

22 TSX: YGR 2,088 2,832 2,134 1,563 1,792 1,807 1,376 1,134 498 473 373 273 $0 $1,000 $2,000 $3,000 $4,000 $5,000 $6,000 2010 2011 2012 2013 Equip Complete Drill 41% reduction in average drilling costs since 2011 Drilling Represents 70%

• f Corporate Costs

Staff count is down and performance is up

23 TSX: YGR

• Acreage within the

liquids/volatile oil fairway

• South Block (Willesden Green)
• 7 Net Sections
• Net Pay ~ 36 m
• OGIP ranges from 70 to

100 BCF/sec

• North Block (Pembina)
• 54 Net Sections
• Net Pay ~ 20 to 24 m
• OGIP ranges from 40 to 50

BCF/sec*

YGR NORTH BLOCK

YGR SOUTH BLOCK

*OGIP estimated internally using geochemical, petrophysical and geomechanical analyses of offset wells and proprietary reservoir studies

24 TSX: YGR YGR acreage is optimal with high average porosity > 6%

YGR Acreage

25 TSX: YGR

• Very active Duvernay area

within proven liquids window

• Majors and Independents

are investing heavily in the play

• Shell, Talisman, Black

Swan/Paramount are executing multi-well horizontal drilling programs immediately adjacent to YGR acreage

TALISMAN HZ WILLGR 13-7-38-5 TALISMAN HZ WILLGR 1-24-38-6 TALISMAN HZ WILLGR 8-24-38-6 TALISMAN HZ WILLGR 12-25-38-6 PARA HZ 103 MEDRIV 8-12-39-5 PARA HZ 103 MEDRIV 16-13-39-5 PARA HZ WILLGR 7-19-39-5 TALISMAN 03 HZ WILLGR 14-9-39-6 YANGARRA HZ FERRIER 9-19-39-6 PARA WILLGR 9-25-39-6 SCL HZ WILLGR 9-27-39-6 SCL HZ 102/ WILLGR 10-27-39-6 SCL HZ 102 FERRIER 12-31-39-7 SCL HZ FERRIER 15-13-39-8 SCL 102 HZ FERRIER 16-13-39-8 SCL HZ FERRIER 9-36-39-8 TALISMAN HZ WILLGR 13-35-40-5 SCL HZ FERRIER 6-11-40-7 SCL HZ FERRIER 7-11-40-7 SCL 102 HZ FERRIER WILLGR 15-13-40-7 SCL HZ FERRIER WILLGR 16-13-40-7 SCL HZ FERRIER 3-21-40-7 SCL HZ 102 FERRIER 4-21-40-7 SCL HZ FERRIER 7-30-40-7 SCL FERRIER 8-30-40-7 SCL HZ FERRIER 15-31-40-7 SCL HZ FERRIER 4-2-40-8 SCL HZ 102 FERRIER 4-4-40-8 SECURE FERRIER 10-7-40-8 SCL HZ FERRIER 16-12-40-8 SCL HZ FERRIER 16-18-40-8 TALISMAN HZ WILLGR 10-3-41-5 TALISMAN 02 HZ WILLGR 7-6-41-5 TALISMAN HZ WILLGR 16-15-41-5 TALISMAN 02 HZ WILLGR 12-32-41-5 TALISMAN 02 HZ WILLGR 4-33-41-5 TALISMAN 03 HZ WILLGR 4-33-41-5 TALISMAN HZ WILLGR 4-1-41-6 ECA HZ WILLGR 8-19-41-6 ECA 102 HZ WILLGR 16-27-41-7 ECA HZ WILLGR 2-35-41-7 ECA 104 WILLGR 8-35-41-7 ECA HZ FERRIER 10-16-41-8 ECA HZ FERRIER 6-27-41-8 ECA HZ FERRIER 4-32-41-8 ECA HZ FERRIER 15-33-41-8 SCL HZ FERRIER 1-24-41-9 SCL HZ 103 FERRIER 2-24-41-9 SCL HZ 102 FERRIER 6-35-41-9 SCL HZ FERRIER 7-35-41-9 MOSAIC WILSONCK 1 ECA HZ WILLGR 11-33-42-6 ECA WILLGR 16-33-42-6 ECA HZ WILLGR 7-3-42-7 ECA HZ WILLGR 1-9-42-7 ECA HZ WILLGR 12-10-42-7 ECA 102 WILLGR 6-3-43-6 ECA 102 HZ WILLGR 8-5-43-6 ECA HZ WILLGR 3-6-43-7

R4W5 R5 R6 R7 R8 R9 R4W5 R5 R6 R7 R8 R9 T38 T39 T40 T41 T42 T43 T38 T39 T40 T41 T42 T43

Yangarra Resources Ltd

DUVERNAY SOUTH

TSX: YGR 26

M M’

Yangarra South Block

TALISMAN HZ FERRIER 3-28-38-6

14-9-38-9

PARA WILLGR 9-25-39-6 SCL HZ FERRIER 3-21-40-7 SCL HZ 102 FERRIER 4-21-40-7 NUTECH WELL

M M '

Paramount Offset Hz well at 08-19-39-5W5 (SL: 09-25-039-06W5) Analogous to 3-28 Talisman 3-28-38-6W5

• Net Pay (YGR South

Block) ~36 m

• Southern Block is de-

risked by adjacent wells

• Continuous Duvernay

formation

Shell Hz @ 3 -21 & 4-21-40-7W5

TSX: YGR 27 TSX: YGR

• Vermillion/Black Swan and Sinopec/Daylight have drilled vertical

and horizontal test wells adjacent to YGR lands

TSX: YGR 28

11-22

7-4 - 49-12W5 Vermillion HZ Offset at 10-28-48-12W5 7-3-47-11W5 (1977) Flowed 400 bbls 7-1-48-10W5 8-32-46-9W5 Sinopec HZ Producer 15-18-49-13W5 Vermillion Strat Test

Net Pay Net Pay Net Pay Net Pay Net Pay

Duvernay Net Pay on YGR acreage ~20-24 m De-risking is underway

8-32

7-3 7-1 10-28 7-4 15-18

Approximate Hz well path

A ‘A A’ A

TSX: YGR 29

* Assumes Yangarra specific heat value

Oil Hedges 2014: 1,200 bbl/d hedged at $98.18/bbl 2015: 1,100 bbl/d hedged at $93.32/bbl Natural Gas Hedges 2014: 5,000 GJ/d hedged at $3.39/GJ or $4.20/mcf* 2015: 2,000 GJ/d hedged at $4.11/GJ or $5.10/mcf* Interest Rate Swaps 4.70% Fixed rate on $10 million (June 2014-June 2018) 4.85% Fixed rate on $10 million (June 2014-June 2018)

TSX: YGR 30

• Increased stage count in laterals from 10 to 24
• Gone from 250 tonnes of sand/well to 540 tonnes of sand/well
• Full mile laterals on all wells with longer reach wells in inventory
• Resin-coated sand tailed in to prevent crushing
• Premium casing reduces friction when pumping fracs, minimizes

casing failures

• Tighter well spacing on sections to maximize recoveries
• Mono-bore drilling reduces drilling times and drilling costs
• Nano technology in drilling mud to help heal loses
• Multi-well Pad drilling to reduce the cost per well
• Multi-well pads allow for zipper fracs

TSX: YGR 31

Company Cash Flow CF/Share Current Share Price Multiple Debt/CF Gas Weighting CF Margin MQL $ 10.3 $ 0.09 $ 0.75 8.73 1.32 58% 44% YGR $ 9.3 $ 0.16 $ 1.60 9.88 1.37 52% 63% PWT $ 231.0 $ 0.47 $ 4.62 9.90 2.55 36% 39% TBE $ 52.1 $ 0.15 $ 1.49 10.00 1.67 10% 36% MEI $ 11.2 $ 0.16 $ 1.64 10.11 0.89 41% 36% DTX $ 52.7 $ 0.59 $ 6.15 10.36 0.70 18% 60% AEI $ 13.2 $ 0.78 $ 8.45 10.90 1.48 20% 40% GXE $ 22.6 $ 0.32 $ 3.52 11.04 1.04 3% 47% RE $ 16.5 $ 0.41 $ 4.59 11.25 0.60 5% 50% RMP $ 48.0 $ 0.39 $ 6.25 15.89 0.52 44% 62% ZAR $ 10.9 $ 0.36 $ 5.83 16.19 2.79 31% 29% BXE $ 60.0 $ 0.31 $ 5.14 16.40 1.96 69% 44% BNP $ 129.1 $ 0.60 $ 10.61 17.61 2.28 69% 50% TOG $ 48.9 $ 0.52 $ 10.97 20.93 1.08 16% 58% DEE $ 14.2 $ 0.09 $ 1.94 21.20 2.90 71% 40% TVE $ 15.8 $ 0.20 $ 4.36 21.48 1.92 36% 45% BNE $ 65.7 $ 2.04 $ 48.68 23.83 0.74 27% 74% CQE $ 13.0 $ 0.06 $ 1.55 25.07 0.52 85% 43% WCP $ 127.6 $ 0.52 $ 14.60 28.06 1.07 28% 55% SPE $ 28.2 $ 0.11 $ 3.04 28.34 0.70 6% 47% RTK $ 6.9 $ 0.09 $ 2.56 28.71 2.58 61% 41% PEY $ 163.1 $ 1.06 $ 35.54 33.49 1.41 90% 73% CJ $ 25.9 $ 0.46 $ 16.04 35.14 0.56 10% 48% KEL $ 31.7 $ 0.25 $ 9.65 38.62 0.29 63% 52% TOU $ 211.6 $ 1.05 $ 42.33 40.33 1.48 87% 66% SRX $ 11.8 $ 0.11 $ 5.04 47.60 1.19 78% 47%

32 TSX: YGR

YGR BXE BNP PWT PEY TOU RMP WCP BNE TOG KEL SPE TBE DTX CQE DEE Production (boe/d) 3,038 37,838 74,709 100,854 77,602 107,997 13,074 34,939 13,356 11,436 13,872 7,399 20,789 12,294 9,695 9,461 Gas Weighting 52% 69% 69% 36% 90% 87% 44% 28% 27% 16% 63% 6% 10% 18% 85% 71% Field Netback $ 42.46 $ 22.37 $ 23.91 $ 33.19 $ 26.47 $ 22.04 $ 42.82 $ 47.27 $ 49.33 $ 50.61 $ 26.23 $ 50.58 $ 38.32 $ 49.49 $ 20.24 $ 21.63 Op Costs $ 7.97 $ 10.11 $ 9.53 $ 21.45 $ 2.74 $ 7.25 $ 7.67 $ 14.80 $ 15.17 $ 15.35 $ 14.43 $ 22.72 $ 21.37 $ 11.58 $ 9.09 $ 12.95 Net Royalty $ 2.50 $ 7.00 $ 4.34 $ 8.95 $ 2.04 $ 2.97 $ 13.42 $ 9.79 $ 7.90 $ 13.69 $ 7.24 $ 13.78 $ 15.12 $ 16.01 $ 4.35 $ 5.77 G&A Costs $ 2.24 $ 1.75 $ 1.19 $ 3.66 $ 0.13 $ 0.65 $ 1.09 $ 1.50 $ 2.12 $ 2.11 $ 0.73 $ 2.09 $ 1.76 $ 1.41 $ 2.12 $ 1.65 Cash Flow ($ million) $ 9.3 $ 60.0 $ 129.1 $ 231.0 $ 163.1 $ 211.6 $ 48.0 $ 127.6 $ 65.7 $ 48.9 $ 31.7 $ 28.2 $ 52.1 $ 52.7 $ 13.0 $ 14.2 Debt ($ million) $ 51 $ 470 $ 1,176 $ 2,360 $ 922 $ 1,256 $ 101 $ 545 $ 195 $ 212 $ 37 $ 79 $ 348 $ 148 $ 27 $ 165 Debt/CF 1.37 1.96 2.28 2.55 1.41 1.48 0.52 1.07 0.74 1.08 0.29 0.70 1.67 0.70 0.52 2.90 Market Cap ($ million) $ 92 $ 984 $ 2,274 $ 2,287 $ 5,462 $ 8,536 $ 763 $ 3,582 $ 1,566 $ 1,025 $ 1,222 $ 798 $ 521 $ 546 $ 327 $ 302 EV ($ million) $ 144 $ 1,454 $ 3,450 $ 4,647 $ 6,384 $ 9,792 $ 864 $ 4,126 $ 1,761 $ 1,237 $ 1,259 $ 877 $ 870 $ 694 $ 354 $ 467 EV/boe $ 47,269 $ 38,436 $ 46,174 $ 46,076 $ 82,271 $ 90,668 $ 66,082 $118,098 $131,884 $108,148 $ 90,789 $118,465 $ 41,837 $ 56,459 $ 36,522 $ 49,340 Current Share Price $ 1.60 $ 5.14 $ 10.61 $ 4.62 $ 35.54 $ 42.33 $ 6.25 $ 14.60 $ 48.68 $ 10.97 $ 9.65 $ 3.04 $ 1.49 $ 6.15 $ 1.55 $ 1.94 Cashflow Margin 63% 44% 50% 39% 73% 66% 62% 55% 74% 58% 52% 47% 36% 60% 43% 40% Q3 Cashflow Multiple 2.47 4.10 4.40 2.48 8.37 10.08 3.97 7.01 5.96 5.23 9.66 7.08 2.50 2.59 6.27 5.30

33 TSX: YGR

YGR AEI MQL TVE CJ GXE SRX RE MEI ZAR RTK Production (boe/d) 3,038 4,847 5,143 5,765 7,586 6,713 7,161 4,747 4,644 6,054 3,948 Gas Weighting 52% 20% 58% 36% 10% 3% 78% 5% 41% 31% 61% Field Netback $ 42.46 $ 41.56 $ 28.53 $ 42.92 $ 43.11 $ 41.42 $ 20.60 $ 40.63 $ 37.19 $ 35.37 $ 23.94 Op Costs $ 7.97 $ 15.85 $ 14.90 $ 14.84 $ 23.80 $ 21.78 $ 11.22 $ 14.03 $ 11.12 $ 18.42 $ 15.41 Net Royalty $ 2.50 $ 17.33 $ 6.54 $ 8.86 $ 10.53 $ 14.97 $ 5.98 $ 20.90 $ 23.72 $ 13.38 $ 6.90 G&A Costs $ 2.24 $ 2.68 $ 3.49 $ 3.30 $ 3.07 $ 3.20 $ 0.98 $ 2.04 $ 4.93 $ 7.56 $ 2.46 Cash Flow ($ million) $ 9.3 $ 13.2 $ 10.3 $ 15.8 $ 25.9 $ 22.6 $ 11.8 $ 16.5 $ 11.2 $ 10.9 $ 6.9 Debt ($ million) $ 51 $ 78 $ 55 $ 122 $ 58 $ 94 $ 56 $ 39 $ 40 $ 121 $ 72 Debt/CF 1.37 1.48 1.32 1.92 0.56 1.04 1.19 0.60 0.89 2.79 2.58 Market Cap ($ million) $ 92 $ 143 $ 90 $ 340 $ 909 $ 249 $ 561 $ 185 $ 113 $ 176 $ 199 EV ($ million) $ 144 $ 221 $ 145 $ 461 $ 967 $ 343 $ 617 $ 225 $ 153 $ 297 $ 271 EV/boe $ 47,269 $ 45,629 $ 28,187 $ 79,983 $127,439 $ 51,152 $ 86,169 $ 47,352 $ 32,986 $ 49,097 $ 68,594 Current Share Price $ 1.60 $ 8.45 $ 0.75 $ 4.36 $ 16.04 $ 3.52 $ 5.04 $ 4.59 $ 1.64 $ 5.83 $ 2.56 Cashflow Margin 63% 40% 44% 45% 48% 47% 47% 50% 36% 29% 41% Q3 Cashflow Multiple 2.47 2.72 2.18 5.37 8.79 2.76 11.90 2.81 2.53 4.05 7.18

34 TSX: YGR

Third Quarter 2014 Production 3,039 boe /d Liquid Content 48% Sales Price $ 52.80 /boe Royalty income 0.90 / boe Royalty expense (3.40) / boe Production costs (6.45) / boe Transportation costs (1.52) / boe Field Operating netback $ 42.33 / boe Commodity contract settlement (5.13) / boe Operating netback $ 37.20 / boe G&A and other (excludes non-cash items) (2.23) / boe Finance expenses (1.42) / boe Cash flow netback $ 33.54 / boe

TSX: YGR 35

Statements in this presentation may contain forward-looking information including expectations of future production and components of cash flow and earnings. Forward looking statements or information are based on current expectations, estimates and projections that involve a number of risks and uncertainties which could cause actual results to differ materially from those anticipated by the Company and described in the forward looking statements or information. These risks and uncertainties which may cause actual results to differ materially from the forward looking statements or information include, among other things: general economic and business conditions; the risk of instability affecting the jurisdictions in which the Company operates; the risks of the oil and natural gas industry, such as operational risks in exploring for, developing and producing crude oil and natural gas and market demand; the possibility that government policies or laws may change or governmental approvals may be delayed or withheld; risks and uncertainties involving geology of oil and natural gas deposits; the uncertainty of reserves estimates and reserves life; the ability of the Company to add production and reserves through acquisition, development and exploration activities; the Company’s ability to enter into or renew leases; potential delays or changes in plans with respect to exploration or development projects or capital expenditures; the uncertainty of estimates and projections relating to production (including decline rates), costs and expenses; fluctuations in oil and natural gas prices, foreign currency exchange rates and interest rates; risks inherent in the Company’s marketing operations, including credit risk; health, safety and environmental risks; and uncertainties as to the availability and cost of financing. Readers are cautioned that the foregoing list is not exhaustive of all possible risks and uncertainties. The reader is cautioned not to place undue reliance on this forward-looking information. The forward looking statements or information contained in this presentation are made as of the date hereof and the Company undertakes no obligation to update publicly or revise any forward looking statements or information, whether as a result of new information, future events or

• therwise unless required by applicable securities laws. The forward looking statements or information contained in this

presentation are expressly qualified by this cautionary statement.

36 TSX: YGR

Natural gas has been converted to a barrel of oil equivalent (Boe) using 6,000 cubic feet (6 Mcf) of natural gas equal to one barrel of oil (6:1), unless otherwise stated. The Boe conversion ratio of 6 Mcf to 1 Bbl is based on an energy equivalency conversion method and does not represent a value equivalency; therefore Boe's may be misleading if used in isolation. References to natural gas liquids ("NGLs") in this news release include condensate, propane, butane and ethane and one barrel of NGLs is considered to be equivalent to one barrel of crude oil equivalent (Boe). One ("BCF") equals one billion cubic feet of natural gas. One ("Mmcf") equals one million cubic feet of natural gas. Reserve Definitions: (a) "Proved" reserves are those reserves that can be estimated with a high degree of certainty to be recoverable. It is likely that the actual remaining quantities recovered will exceed the estimated proved reserves. (b) "Probable" reserves are those additional reserves that are less certain to be recovered than proved reserves. It is equally likely that the actual remaining quantities recovered will be greater or less than the sum of the estimated proved plus probable reserves. (c) "Developed" reserves are those reserves that are expected to be recovered from existing wells and installed facilities or, if facilities have not been installed, that would involve a low expenditure (e.g. when compared to the cost of drilling a well) to put the reserves on production. (d) "Developed Producing" reserves are those reserves that are expected to be recovered from completion intervals open at the time

• f the estimate. These reserves may be currently producing or, if shut-in, they must have previously been on production, and the

date of resumption of production must be known with reasonable certainty. (e) "Developed Non-Producing" reserves are those reserves that either have not been on production, or have previously been on production, but are shut in, and the date of resumption of production is unknown. (f) "Undeveloped" reserves are those reserves expected to be recovered from know accumulations where a significant expenditure (for example, when compared to the cost of drilling a well) is required to render them capable of production. They must fully meet the requirements of the reserves classification (proved, probable, possible) to which they are assigned. (g) The Net Present Value (NPV) is based on Deloitte AJM Forecast Pricing and costs. The estimated NPV does not necessarily represent the fair market value of our reserves. There is no assurance that forecast prices and costs assumed in the Deloitte AJM evaluations will be attained, and variances could be material.

37 TSX: YGR

Yangarra Resources Ltd. 1530, 715 – 5 Ave. SW Calgary, Alberta T2P 2X6 403-262-9558