1

LNG Investment ConferenceSaturday, April 12, 2014

2

The Painted Pony Position

Future LNG

SupplyBC

MontneyDevelopment

PositionedFor

Growth

Positioned to be a leading gas supplier to Canada’s west coast LNG exports

High working interest, large, contiguous asset base Low cost, ideal heat content natural gas for Asian LNG

import markets All Montney lands located in BC On existing & proposed pipeline routes

Positioned to be a leading Montney producer Accelerating production and cash flow growth Continued de-risking of main producing properties Expanding processing capacity to maximize value Driving costs down and increasing capital efficiencies

through innovation

Positioned for organic and rapid growth! Repeatable performance, underpinned by excellent per-well economics Utilize internally generated cash flows and existing credit facilities to build on economies of scale

3

Corporate Snapshot - Financial

PPY TSX Trading Symbol

88.9 million Shares Outstanding (1)

96.3 million Fully Diluted Shares Outstanding ($8.79 average strike price)(1)

$6.05 - $10.70 52-Week Trading Range

$900 million Market Capitalization ($10.00/share)

$125 million Syndicated Bank Credit Facilities

$45 million Net Debt (as at Dec. 31, 2013)

$1.7 billion Net Asset Value (NAV)(2)*

$18.90 NAV Per Share(2)*

(1) As at Mar. 31, 2014(2) As at Dec. 31, 2013*NAV calculated as P+P reserves as at Dec. 31, 2013 as prepared by GLJ Petroleum Consultants, plus undeveloped land evaluated by Seaton-Jordan & Associates Ltd., less estimated net debt

4

Corporate Snapshot

9,312 boe/d Q4 2013 Average Production (16% oil & liquids)

9,750 boe/d Q1 2014 Estimated Production (13% oil & liquids)

13,500 boe/d Q2 2014 Estimated Production (14% oil & liquids)

1.7 Tcfe Proved + Probable Reserves(1)G

$1.5 billion NPV10 Proved + Probable Reserves(1)G

7.0 Tcfe Best Estimate Contingent Resources(1)G

$4.7 billion NPV10 Best Estimate Contingent Resources(1)G

$215 million Undeveloped Land Value(1)*

$138 million 2014 Forecast Net Capital Budget ($149 million before planned facility disposition)

18 Montney wells 17.0 net in 2014

(1) As at Dec. 31, 2013*Undeveloped land evaluated by Seaton-Jordan & Associates Ltd., as at Dec. 31, 2013

5

2014 Operational Update

1 (1.0 net) Montney well currently drilling at 91-F/94-B-16 pad 5 (5.0 net) Montney wells drilled to date in 2014 4 (4.0 net) Montney wells completed to date in 2014 All wells completed using open hole ball-drop technology 100% working interest 25 MMcf/d gas processing and condensate

stabilization facility at Townsend currently operational Increased access to Blair AltaGas plant capacity by 7 MMcf/d to

~40 MMcf/d Undergoing engineering study on up to 190 MMcf/d shallow-cut

refrigeration plant at Townsend, to be built in 2015 Production expected to increase to 13,500 boe/d in Q2 2014

6

Impressive & Consistent Reserves Growth

145% compound annual growth in reserves from 2007 to 2013 90% compound annual growth in reserves per share

Reserves per share are calculated by dividing P+Preserves by million basic weighted average shares during the year. For the year ended 2013, Painted Pony’s P+P reserves were 290.3 MMboe and the Company had 88.5 mm shares outstanding.

2007 2008 2009 2010 2011 2012 20130

50

100

150

200

250

300

350

0.00

0.50

1.00

1.50

2.00

2.50

3.00

3.50

0.040.15 0.15

0.64

1.96

2.17

3.28

Probable Reserves

Proved Reserves

P+P Reserves Per Share

Res

erve

s (M

Mbo

e)

Res

erve

s Pe

r Sha

re (b

oe/S

hare

)

290.3mmboe

191.1mmboe

7

Impressive & Consistent Production Growth

2007 2008 2009 2010 2011 2012 2013 2014 E0

5,000

10,000

15,000

0

50

100

150

Gas

Oil & Liquids

Production Per Million Shares

Prod

uctio

n (b

oe p

er d

ay)

boe

per d

ay /

Mill

ion

Shar

es

131% compound annual growth in production from 2007 to 2013 67% compound annual growth in production per million shares

from 2007 to 2013

Production per million shares is calculated by dividing average production in the time period by the basic weighted average shares for the same time period. 2013 production averaged 8,693 boe/d and the Company had 88.4 mm basic weighted average shares outstanding. Amounts and estimates beyond 2013 are those of Painted Pony’s management as of the date hereof

13,000boe/d

8,693boe/d

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Natural Gas Hedging: Risk Management Strategy

22.1 MMcf/d average fixed AECO price of $4.09/Mcf in Q2 2014

23.7 MMcf/d average fixed AECO price of $4.14/Mcf in Q3 2014

23.7 MMcf/d average fixed AECO price of $4.14/Mcf in Q4 2014

23.7 MMcf/d average fixed AECO price of $4.34/Mcf in Q1 2015

Painted Pony’s 2014 budget price of $3.71/Mcf*

*GLJ Oct. 1, 2013 annual average 2014 pricing NYMEX $4.00/MMBtu US (CDN $3.71/MMBtu AECO)

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Canada’s Proposed West Coast LNG Projects

Fort St. John

Prince George

Spectra Mainline 36” and 30”

PNG Mainline 10”

Montney Trend

Pacific Ocean

Fort Nelson

Kitimat

AB

PPY Land

British Columbia

Proposed TransCanada

Shell 42”

Proposed Spectra

BG Group

Proposed TransCanada

Petronas

Chevron-Apache Approved Pipeline

42”

Prince Rupert

Vancouver

Sumas

Squamish

Woodfibre

To Jordan Cove LNG

New natural gas liquefaction plants expected to be constructed from 2013-2030 will control ~52% of global LNG production to fill the supply-demand gap(2)

Western Canadian LNG exports offer best shipping times to key Asian markets

Lower average ambient temperatures of 6˚C results in 20% - 30% less energy use in liquefaction

Canada’s large upstream & midstream oil and gas industry insulates producers from costly increases

Six Canadian west coast LNG export projects approved by the NEB with total capacity of ~14.3 Bcf/d, 4 additional west coast LNG plants under review with further capacity of ~7.4 Bcf/d

Global LNG Supply Challenge(1)

(1) BG Interpretation of Wood Mackenzie Data, Aug. 2012(2) PIRA - LNG Special Report, Dec. 2012

10

PPY’s Advantage in the Montney

British Columbi

a

Excellent rate of return at domestic gas prices

Large contiguous land base located 100% in BC (the “BC Advantage”)

High working-interest On existing & planned pipeline routes High-rate, sweet, liquids rich

natural gas offers increased value from liquids and low processing costs

Low operating & transportation costs Year-round access Excellent royalty structure Ideal gas heating value for LNG

exportsClear line-of-sight to

West Coast LNG projects

11

PPY Montney – Strong Progress To Date

Painted Pony’s

Daiber d-44-C Montney Well 100 foot test flare

24.5 MMcf/d @ 2,700 psi

129,600 net acres (203 net sections)L

73% Average working interest

54 (33.7 net) horizontal Montney wells drilled to date

~50 MMcfe/d (~8,300 boe/d) Q1 2014gas & gas-liquids production

Royalty incentive of ~$2.2 million per horizontal well vs. eastern BC Montney of ~$0.8 million per horizontal well

PPY Montney Project

12

Our Montney Advantage

PPY lands situated in a Montney ‘sweet spot’ - thick, stacked, over-pressured & liquids rich gas

Extremely thick - average >300 meters thick; up to 500 meters thickR

Stacked reservoir layers proven commercial - upper, middle, & lower Montney

Reduce costs & improve well performance - open hole ball-drop completion technology adopted in 2013 and proven in 2014

PPY well performance is top decile - within overall BC Montney production

Fully gas-charged - with no underlying water

Highly over-pressured - in excess of 1.6 times normal pressures

High liquids content - average of 13 bbls/MMcfG of recoverable C3+

Ideal BTU heating value - for LNG exports with sales gas of 1,080 BTU/Mcf

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Horn River

300 mThickR

Upper

Middle

Lower

Future Hz Layer Exploitable Gas Column

On equivalent Thickness Scale

An Exceptional Stacked Gas Resource Play . . .

Montney PPY Montney Attributes Sweet gas (no H2S)

Very low CO2

High heat content High liquids content Year-round access

Horn River Attributes Sour gas (high H2S)

High CO2

Low heat content Dry gas (no liquids) Winter only access

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Stacked Exploitable Horizons - Substantially De-risked

Source: Company records and geoSCOUT.The production rates disclosed above are test rates and are not necessarily indicative of current production rates.

Blair

Cypress

Daiber

Townsend

PPY landsPPY operated Montney wellsPPY non-operated Montney wellsCompetitor Montney wells

PPY Well Test Results PPY has participated in a total of

54 (33.7 net) horizontal Montney wells

Upper Montney 7.0 MMcf/d average peak test rate 10.8 MMcf/d maximum peak test

Middle Montney 8.0 MMcf/d average peak test rate 13.9 MMcf/d maximum peak test

Lower Montney 8.3 MMcf/d average peak test rate 24.5 MMcf/d maximum peak test

WestBlair

d-C44-C/94-B-16 upper Montney

10.8 MMcf/d Test Rated-D44-C/94-B-16 lower Montney

14.8 MMcf/d In-Line Flow Rate

a-A11-J/94-B-09 lower Montney

8.0 MMcf/d & 160 bbls/d liquids

1,460 boe/d production

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Montney Reserves & Contingent Resources* (Dec. 31, 2013)

Total Proved + Probable ReservesG

NPV10% $1.4 billion 1.7 Tcfe (285 MMboe) Including 20.1 MMbbl of recoverable NGL’s

(C3+) at an average 13 bbl/MMcf 17% of lands booked with P+P reserves

Best Estimate of Contingent Economically Recoverable ResourcesGP

NPV10% $4.7 billion 7.0 Tcfe (1,170 MMboe) Including 82.8 MMbbl of NGL’s

Best Estimate of Prospective ResourcesGP

NPV10% $1.7 billion 7.3 Tcfe (1,219 MMboe) Including 86.2 MMbbl of NGL’s

PPY Montney Reserves & Resources Map

~54% of PPY Lands currently estimated to contain P+P Reserves & Contingent ResourcesGP

BlairWest Blair

Daiber

Townsend

Cypress

Legend

Wells

Drilled Wells

Montney

2P - 3 Layers2P - 1 or 2 LayersContingent

Prospective Resources

Montney 100% WI Montney 40-90% WIMontney 20% WI

16

Continuing Cost Reduction from Technology Advances

1 2 3 4 5 6 70

1,000

2,000

3,000

4,000

5,000

6,000

7,000

8,000

Ball-Drop vs Perf & Plug Completions Comparison

a-A91-F/94-B-16 (Ball-Drop)

a-91-F/94-B-16 (Perf & Plug)

Production Month

Prod

ucing

Rat

e (M

cf/d)

38% Improvement in IP30d

36% Improvement at P210d

a-A91-F/94-B-16 Ball-Drop CompletionPeak test rate: 8.7 MMcf/d (1,870 boe/d)

Cumulative production: 1,035 MMcf over 210 days

a-91-F/94-B-16 Perf-and-Plug Completion

Peak test rate: 6.7 MMcf/d (1,450 boe/d)

Cumulative production: 761 MMcf over 210 days

PPY-operated Ball-Drop Completions

Blair 14-F (1)

Daiber 44-C (2)

Townsend: 11-J (2)56-H (2)

$750,000 per wellAverage cost-savings realized to-date using the

Ball-Drop system vs Perf & Plug (10 wells 9.5 net)

Blair 91-F (1)

Blair 41-F (2)

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PPY Blair-

Townsend Swan

Sundown

SunriseSunset

Groundbirch

Septimus

TownAltares Lily

Blueberry

Industry-Leading Unconventional BC Montney Well Performance

PPY Blair-Townsend Wells Top Decile Well Performance:

Initial 3-month average rate (5.2 MMcf/d) First year average rate (3.7 MMcf/d) 12th-month rate (2.7 MMcf/d)

Source: geoSCOUT12 Month Average Rate 12th Month RateInitial 3 Month Average Rate

47% Decline

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Situated in a High-Pressure Cell . . .

Approximate Transition to

Montney Normal Pressure

3) Septimus

MontneyPressure-Depth Plot

Pressure-depth position of established gas pools

Increasing Pressure

Incr

easi

ng D

epth

Normal Pressure Reference Line

12) Town

2900 PSI 4350 PSI 5800 PSI

11) Blueberry

1) Parkland

2) Dawson

6) E. Swan7) W. Swan

4) Sunrise 5) Heritage

10) AltaresNorthern Montney

High-Pressure Cell

Southern Montney High-Pressure Cell

1

2 34

56 8

10

7

9

8) Groundbirch9) Saturn

11 12

PPYHigh-Pressure Montney Gas

LowerOver-Pressure

HigherOver-Pressure

Higher Pressure:

>> Higher Gas-in-Place

>> Higher Productivity

>> Moderated Decline

Data Sources: GeoScout, Canadian Discovery, PPY Internal Analyses

Northern High-Pressure Cell

Southern High-Pressure CellGraham

High-Pressure Boundary

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Montney Development EconomicsR

*GLJ Oct. 1, 2013 annual average 2014 pricing NYMEX $4.00/MMBtu US (CDN $3.71/MMBtu AECO) **The internal rate of return on an investment or project is the "annualized effective compounded return rate" that makes the net present value of all cash flows from a particular investment equal to zero

$7.2 mm Drill, complete, equip and tie-in costs 5.5 MMcf/d Initial 30 day production rate 7 Bcf P+P reserves per wellR

14 bbls/MMcf Liquids content (condensate, butane, and propane) $7.1 mm NPV 10% per well*

46.7% Internal rate of return**

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 180

1,000

2,000

3,000

4,000

5,000

6,000

7,000PPY Montney Well Production by Zone

Lower Montney (23 wells)

Middle Montney (6 wells)

Upper Montney (14 wells)

6 Bcf Type Well

7 Bcf Type Well

Production Month

Prod

ucin

g Ra

te (M

cf/d

)

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 180

1,000

2,000

3,000

4,000

5,000

6,000

7,000 PPY Average Montney Well Production

Average of all PPY Montney Wells

Ball-Drop Completions (6 Wells)

6 Bcf Type Well

7 Bcf Type Well

Production Month

Prod

ucin

g Ra

te (M

cf/d

)

20

Montney Development Economics Flat Price SensitivitiesR

$7.1 mm NPV10

46.7% IRR

$5.00 Flat NYMEX

$5.50 Flat NYMEX

$4.50 Flat NYMEX

$4.00 Flat NYMEX

$3.50 Flat NYMEX

$3.00 Flat NYMEX

PPY Average Current Well*

P+P reserves per well: 7 BcfR

Liquids: 14 bbls/MMcfIP30: 5.5 MMcf/dDrill, complete, and tie-in cost: $7.2 mm

Flat NYMEX Pricing Sensitivities

$4.53 2014 NYMEX strip

*5 year plan price deck beginning in 2014 at NYMEX $4.00/MMBtu US and escalating to $4.90/MMBtu US in 2018. $4.53 NYMEX calendar 2014 price. National Bank of Canada, Mar. 6, 2014

21

2014 Montney Development Plan

2014 activities with $140 million in capital and interest costs… Drill 18 (17.0 net) Montney wells & complete using ball-drop technology Completed construction of 100% working interest, 25 MMcf/d gas

dehydration and condensate stabilization facility at Townsend Expand the Daiber gas facility from 25 MMcf/d to 50 MMcf/d in Q3 2014 Initiated engineering study on 190 MMcf/d capacity refrigeration facility

at Townsend to be built in 2015

…estimated to generate… $100 million cash flow 13,000 boe/d average production

…and resulting in $85 million in net debt outstanding at year end 2014 with a debt to

trailing cash flow ratio of 0.9x

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Montney Model for Production Growth

YearNet MontneyWells Drilled

Capital &Interest

($mm)

CashFlow**($mm)

Year-EndDebt ($mm)

Total Average Production

(boe/d)

Debt to Cash Flow

(D/CF x)

NYMEX Price

($/MMBtu)

2014 17 140 100 85 13,000 0.9x 4.00

2015 32 294 160 219 20,500 1.4x 4.42

5 year plan results in ~100,000 boe/d 2018 exit production rate ~64% compound annual growth in production from 2014 to 2018

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With an Impressive All-In Production Cost

Excellent earnings potential in current commodity price environment Estimated price PPY received in NEBC $4.83 / Mcfe in January 2014* Attractive operating netbacks, C$3.21 per Mcfe at C$4.42/Mcf AECO in January 2014*

Series10.00

1.00

2.00

3.00

4.00

5.00

$ / M

cfe

$1.62/Mcfe**

Operating & Transportation Costs, and Royalties

$3.21/McfeOperating Netback

*January 2014 PPY realized price $4.83/Mcfe ** January 2014 average

Estimated Price Received by PPY in Jan. 2014*

Operating & Transportation Costs, and Royalties = C$1.62/Mcfe January 2014 Average

North American Natural Gas Price Forecast, 2014

NYMEX Historical NYMEX Futures GLJ Jan. 1, 2014

24

2014: drill 6 (6.0 net) Montney wells Completed 2 (2.0 net) wells in Q1 2014 that were

drilled in Q4 2013

New Montney gas producer: a-B11-J/94-B-09 lower Montney producing 2 (2.0 net) new wells flowing at 12.0 MMcf/d Additional condensate of 480 bbls/d

New 2014 Townsend facility: Completed on time and on budget 25 MMcf/d (100% PPY) Existing third party facility access

10-12 MMcf/d

Future 2015 facility Up to 190 MMcf/d

Spectra T-North Pipeline

Facility operational Q2 2014: 25 MMcf/dFuture facility: 2015: 190 MMcf/d

2014 locationsPreviously Drilled HZ WellsFacilities

100% WI40%-83% WI20% WI

U. & L. Montney wellsFlowing at 12.0 MMcf/dCondensate of 480 bbls/d

Townsend

25

Blair-Daiber

2014: drill 12 (11.0 net) Montney wells Drilled 5 (5.0 net) wells to date in 2014 and

completed 2 (2.0 net) wells Currently drilling 1 (1.0 net) wells

Blair well results: Completed 2 (2.0 net) wells at the 41-F/94-B-16

pad flowing at a combined rate of 20.8 MMcf/d Additional 15 bbls/MMcf of NGLs (312 bbls/d) Both wells completed using open hole

ball-drop technology

Facilities capacity: Future West Blair facility

25 MMcf/d compression & dehydration facility

AltaGas Blair Plant 65 – 78 MMcf/d capacity (~40 MMcf/d net to PPY)

Daiber 44-C/94-B-16 facility expansion From current 25 MMcf/d to 50 MMcf/d in Q3 2014

Spectra T-North Pipeline

West Blair Blair

Daiber

41-F/94-B-16 Pad2 (2.0 net) U. Montney wells20.8 MMcf/d combined rate

2014 LocationsPreviously Drilled HZ Wells 45 (27.6 net) Blair & Cameron to date

100% Working Interest Lands29%-80% Working Interest Lands20% Working Interest Lands

Drilling 1 (1.0 net) well

26

Industry Transactions – Comparable Transactions*

1RBC Capital Markets, Celtic Exploration Ltd., Oct. 18, 20122FirstEnergy Capital, Progress Energy Resources Corp., Jul. 30, 20123FirstEnergy Capital, Talisman Energy Inc., Nov. 11, 20134FirstEnergy Capital, Talisman Energy Inc. Mar. 11, 2011 5Scotiabank GBM, Encana Corporation, Feb. 21, 20126FirstEnergy Capital, Encana Corporation, Feb. 22, 2012 7Reserves valued at $1.27/mcfe and $24.19/boe. Land valued at $15,000/acre and $41,200/acre*The estimates of value presented above are based on historical transaction metrics and are not necessarily indicative of the current fair value of the company's lands.

Painted Pony Comparable Transaction Valuation

Acquisitions P+P Reserves Reserves Metric ($/boe)

Exxon–Celtic 138.4 MMboe ~$24.19/boe1

Petronas–Progress 323.0 MMboe ~$17.93/boe2

Petronas–Talisman 0.6 Tcfe ~$1.27/Mcfe3

Joint Ventures Net Acres Acreage Metric ($/Acre)

Talisman–Sasol 54,000 ~$36,700 - $41,2004

Encana–Mitsubishi 164,000 ~$15,0005 - $17,7006

Painted Pony Relevant Figures

Painted Pony BC Reserves (P+P): 285 MMboe (1.7 Tcfe)G

Painted Pony net Montney rights: 129,600 net acresL

Painted Pony Comparable Valuation

Implied Value of PPY Assets: ~$1.9 billion - $6.9 billion7

PPY Market Capitalization ($10.00/share): $900 million

27

Bakken Assets: Expanding South

30 miles/50 kmViewfield

Weyburn

Estevan

Kisbey

Huntoon

Midale

Flat Lake

HummingbirdTrough

OungreHoffer

Taylorton

Canada

USA

Weyburn

Border Torquay Play

Cities

Known Bakken oil pools

PPY Interest Lands

3 (1.6 net) 2014 locations

Torquay Producers

Torquay Licenses

Tableland

28

Painted Pony: The Best Pony in the Race

Excellent Montney Asset Base Excellent economics at domestic gas prices Large, contiguous land position located 100% in BC (203 net sections) High working interest (73%) High rate, liquids rich, sweet natural gas wells Proven low cost Montney operator

Ideally located and timed for LNG projects On existing and proposed pipeline routes to Canada’s & US’ west coast Ideal heating value gas for LNG of 1,080 Btu/scf Accelerating production and cash flow growth Increasing processing capacity and value realization from increased liquids

Repeatable, attractive play economics Utilizing current financial capacity to build on economies of scale

29

Appendices & Disclosures

30

Analyst Coverage

Analyst Institution Target Price DateJeremy McCrea AltaCorp Capital $14.00 Apr. 11, 2014

Anthony Petrucci Canaccord Genuity Corp. $16.00 Apr. 10, 2014

Adam Gill CIBC World Markets $11.75 Apr. 11, 2014

Garett Ursu Cormark Securities Inc. $17.00 Apr. 10, 2014

Cody Kwong FirstEnergy Capital $15.50 Apr. 11, 2014

Dan Payne National Bank Financial $12.00 Apr. 10, 2014

Ken Lin Paradigm Capital Inc. $12.00 Apr. 10, 2014

Michael Harvey RBC Capital Markets $14.00 Apr. 10, 2014

Cameron Bean Scotiabank Global Banking & Markets $12.00 Apr. 10, 2014

Michael Dembicki TD Securities $16.00 Apr. 10, 2014

31

Canada’s Proposed West Coast LNG Projects

Fort St. John

Prince George

Spectra Mainline 36” and 30”

PNG Mainline 10”

Montney Trend

Pacific Ocean

Fort Nelson

Kitimat

AB

PPY Land

British Columbia

Proposed TransCanada

Shell 42”

Proposed Spectra

BG Group

Proposed TransCanada

Petronas

Chevron-Apache Approved Pipeline

42”

Prince Rupert

Vancouver

Sumas

Proposed LNG Projects Capacity

Exxon – ImperialWCC LNG: 2022 ~4.0 Bcf/d

Shell – PetroChina, Mitsubishi, KOGASLNG Canada: 2019 ~3.2 Bcf/d

Nexen/CNOOC – Inpex, JGCAurora Liquefied Natural Gas Ltd.: 2017 ~3.1 Bcf/d

BG GroupPrince Rupert LNG: 2020 ~2.9 Bcf/d

Petronas-JapexPacific Northwest LNG: 2018 ~2.6 Bcf/d

Kitsault Energy Ltd.Kitsault Energy Ltd. (Privately Held): 2018 ~2.6 Bcf/d

Veresen Inc.Jordan Cove LNG: 2019 ~1.4 Bcf/d

Chevron – ApacheKM LNG: 2017 ~1.3 Bcf/d

AltaGas – IdemitsuTriton LNG: 2017 ~0.3 Bcf/d

Pacific Oil & GasWoodfibre LNG: 2017 ~0.3 Bcf/d

Total Filed Application Capacity (NEB): ~21.7 Bcf/d

Squamish

Woodfibre

To Jordan Cove LNG

32

Buckinghorse Shale Sweet Gas Resource Play

*Source: BC Ministry of Energy, Mines & Petroleum Resources, Oil & Gas Division. British Columbia Oil and Gas 2009 – Yours to Explore Management is unable to confirm that the estimate was prepared by a qualified reserves evaluator or audited or in accordance with the COGE Handbook

800 m

1,000 m

300 m

60 bcf/section per 100 m thickness*

800 m thick on PPY landsR

Vertical well development at 16-32 wells/section

Zone is shallow, ~400 m (1,300 ft) TVD

low cost drilling est. <$0.5 MM

Over pressured (average 0.5 psi/ft)

High heat content gas

102,200 net acres(160 net sec)L

Plan to frac 2 (1.0 net) wells in 2014

3 wells production tested in the areaPPY 100% working interest Buckinghorse rights

PPY joint working interest Buckinghorse rights

Prospective Buckinghorse fairway

Buckinghorse tests

33

PPY Corporate Overview

Legal Burstall Winger LLP

Auditor KPMG LLP

Evaluation Engineers Sproule Associates LimitedGLJ Petroleum Consultants Ltd.

Banks National Bank of CanadaAlberta Treasury BranchCanadian Imperial Bank of Commerce

Corporate Office1800, 736 – 6th Avenue SW, Calgary, AB T2P 3T7

Toll Free Investor 1 (866) 975-0440Tel (403) 475-0440 Fax (403) 238-1487

Email: info@paintedpony.cawww.paintedpony.ca

34

EndnotesMM: Millions

R: Internal Company estimate prepared by a non-independent, qualified reserves evaluator, effective Dec. 31, 2013

L: Land as at Jan. 21, 2014

G: Consolidated report by GLJ Petroleum Consultants Ltd. as at Dec. 31, 2013

P: Total petroleum initially-in-place (“TPIIP”) is defined in the Canadian Oil and Gas Evaluations Handbook. TPIIP 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 in known accumulations, prior to production, plus those estimated quantities in accumulations yet to be discovered. 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 any portion of the resources.

"Contingent Resources" is defined in the Canadian Oil and Gas Evaluation Handbook as those quantities of petroleum estimated, as of a given date, to be potentially recoverable from known accumulations using established technology or technology under development, but which are not currently considered to be commercially recoverable due to one or more contingencies. Contingencies which must be overcome to enable the reclassification of Contingent Resources as reserves can be categorized as economic, non-technical and technical. The Canadian Oil and Gas Evaluation Handbook identifies nontechnical contingencies as legal, economic, environmental, political and regulatory matters or a lack of markets. There are several non-technical contingencies that prevent the classification of the Contingent Resources estimated herein as being classified as reserves. The primary contingency which prevents the classification of the Company's Contingent Resources as reserves is the current early stage of development. Additional drilling, completion and testing data is generally required before Painted Pony can commit to their development. It is also appropriate to classify as Contingent Resources the estimated discovered recoverable quantities associated with a project in the early evaluation stage. Contingent Resources are further classified in accordance with the level of certainty associated with the estimates and may be subclassified based on project maturity and/or characterized by their economic status. As additional drilling takes place, it is expected that the Contingent Resources will be booked into the reserves category. The Contingent Resource and Prospective Resource estimates contained herein, including the corresponding estimates of before tax present value estimates, are estimates only and the actual results may be greater than or less than the estimates provided herein. There is no certainty that it will be commercially viable or technically feasible to produce any portion of the resources.

The most significant positive and negative factors with respect to Painted Pony’s Contingent and Prospective Resource estimates contained herein relate to the fact that the field is currently at an evaluation/delineation stage. Resource-in-place, productivity and capital costs may be higher or lower than current estimates. Additional drilling and testing are required to confirm volumetric estimates and reservoir productivity for the Contingent and Prospective Resources to be reclassified as reserves.

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DisclaimerThis presentation contains a summary of management’s assessment of results and should be read in conjunction with the Consolidated Financial Statements and related Management’s Discussion and Analysis for the year ended December 31, 2013 and Annual Information Form for the year ended December 31, 2013, as filed on SEDAR. This presentation contains certain forward-looking statements, which include assumptions with respect to (i) drilling success; (ii) commodity prices; (iii) production; (iv) reserves; (v) future capital expenditures; (vi) future operating costs; (vii) availability of gas processing facilities; (viii) cash flow; (ix) potential markets for the Company’s production; and (x) the availability of LNG export facilities. The reader is cautioned that assumptions used in the preparation of such information may prove to be incorrect.

Certain information regarding the Company set forth in this document, including statements regarding management’s assessment of the Company’s future plans and operations, the planning and development of certain prospects, production estimates, reserve estimates, productive capacity and economics of new wells, undeveloped land holdings and values, capital expenditures and the timing and allocation thereof (including the number, location and costs of planned wells), facility expansion plans, the total future capital required to bring undeveloped proved and probable reserves onto production, and expected production growth, may constitute forward-looking statements under applicable securities laws and necessarily involve substantial known and unknown risks and uncertainties. These forward-looking statements are subject to numerous risks and uncertainties, certain of which are beyond the Company’s control, including without limitation, risks associated with oil and gas exploration, development, exploitation, production, marketing and transportation, loss of markets, failure of foreign markets to become accessible, the impact of general economic conditions, industry conditions, volatility of commodity prices, currency fluctuations, environmental risks, competition, the lack of availability of qualified personnel or management, inability to obtain drilling rigs or other services, capital expenditure costs, including drilling, completion and facility costs, unexpected decline rates in wells, wells not performing as expected, stock market volatility, delays resulting from or inability to obtain required regulatory approvals and ability to access sufficient capital from internal and external sources, the impact of general economic conditions in Canada, the United States and overseas, industry conditions, changes in laws and regulations (including the adoption of new environmental laws and regulations) and changes in how they are interpreted and enforced, increased competition, fluctuations in foreign exchange or interest rates and market valuations of companies with respect to announced transactions and the final valuations thereof. Readers are cautioned that the foregoing list of factors is not exhaustive. The Company’s actual results, performance or achievement could differ materially from those expressed in, or implied by, these forward-looking statements and, accordingly, no assurance can be given that any of the events anticipated by the forward-looking statements will transpire or occur, or if any of them do so, what benefits the Company will derive therefrom. All subsequent forward-looking statements, whether written or oral, attributable to the Company or persons acting on its behalf are expressly qualified in their entirety by these cautionary statements. Additional information on these and other factors that could affect the Company’s operations and financial results are included in reports on file with Canadian securities regulatory authorities and may be accessed through the SEDAR website (www.sedar.com) or the Company’s website (www.paintedpony.ca), including the Company’s Annual Information Form and MD&A for the year ended December 31, 2013.

The forward-looking statements contained in this document are made as of the date on the front page and the Company assumes no obligation to update publicly or to revise any of the included forward-looking statements, whether as a result of new information, future events or otherwise, except as may be required by applicable securities laws. Certain information contained herein is based on, or derived from, information provided by independent third-party sources. The Company believes that such information is accurate and that the sources from which it has been obtained are reliable. The Company cannot guarantee the accuracy of such information, however, and has not independently verified the assumptions on which such information is based. The Company does not assume any responsibility for the accuracy or completeness of such information.

This document also contains future-oriented financial information and financial outlook information (collectively, "FOFI") about prospective results of operations, future net revenue, share capital, cash flows, and components thereof, all of which are subject to the same assumptions, risk factors, limitations, and qualifications as set forth in the above paragraphs. FOFI contained in this document was made as of the date of this document and was provided for the purpose of providing information about management's current expectations and plans relating to the future. The Company disclaims any intention or obligation to update or revise any forward looking statements or FOFI contained in this document, whether as a result of new information, future events or otherwise, unless required pursuant to applicable securities law. Readers are cautioned that the forward looking statements and FOFI contained in this document should not be used for purposes other than for which it is disclosed herein. The forward looking statements and FOFI contained in this Presentation are expressly qualified by this cautionary statement.

NON-GAAP MEASURESThis presentation contains financial terms that are not considered measures under generally accepted accounting principles (“GAAP”), such as operating netback and working capital. These measures are commonly utilized in the oil and gas industry and are considered informative for management and stakeholders. Specifically, operating netback reflects revenues less royalties and transportation and operating costs divided by production for the period. Painted Pony's method of calculating operating netbacks may not be comparable to that used by other companies. Operating netbacks should not be viewed as an alternative to cash flow from operations or other measures of financial performance calculated in accordance with GAAP. Net working capital is calculated as current assets less current liabilities as at the date of the balance sheet.

Included in this presentation are estimates of the Company's 2014-2018 cash flow which is based on various assumptions as to production levels, commodity prices and other assumptions and in the case of the years other than 2013 and 2014 to date are provided for illustration only and are based on budgets and forecasts that have not been finalized and are subject to a variety of contingencies including prior years results. To the extent such estimates constitute a financial outlook, they were approved by management of the Company in February 2014 and are included to provide readers with an understanding of the Company's anticipated cash flow based on the capital expenditures and other assumptions described and readers are cautioned that the information may not be appropriate for other purposes.

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DisclaimerNOTE REGARDING RESERVES DISCLOSUREThe reserves and resources estimates contained herein, including the corresponding estimates of future net revenues, are estimates only and the actual results may be greater than or less than the estimates provided herein. There is no certainty that it will be commercially viable to produce any portion of the resources.

"Contingent Resources" is defined in the Canadian Oil and Gas Evaluation Handbook as those quantities of petroleum estimated, as of a given date, to be potentially recoverable from known accumulations using established technology or technology under development, but which are not currently considered to be commercially recoverable due to one or more contingencies. Contingencies may include factors such as economic, legal, environmental, political, and regulatory matters, or a lack of markets. It is also appropriate to classify as Contingent Resources the estimated discovered recoverable quantities associated with a project in the early evaluation stage. Contingent Resources are further classified in accordance with the level of certainty associated with the estimates and may be subclassified based on project maturity and/or characterized by their economic status.

"Total Petroleum Initially-In-Place" or "TPIIP" 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 in known accumulations, prior to production, plus those estimated quantities in accumulations yet to be discovered (equivalent to “total resources”).

"Reserves" are estimated remaining quantities of oil and natural gas and related substances anticipated to be recoverable from known accumulations, as of a given date, based on the analysis of drilling, geological, geophysical, and engineering data; the use of established technology; and specified economic conditions, which are generally accepted as being reasonable. Reserves are further classified according to the level of certainty associated with the estimates and may be subclassified based on development and production status.

"Prospective Resources" are those quantities of petroleum estimated, as of a given date, to be potentially recoverable from undiscovered accumulations by application of future development projects. Prospective resources have both an associated chance of discovery and a chance of development. Prospective Resources are further subdivided in accordance with the level of certainty associated with recoverable estimates assuming their discovery and development and may be subclassified based on project maturity.

The most significant positive and negative factors with respect to the resource estimates relate to the fact that the field is currently at an evaluation/delineation stage. The Montney formation is aerially extensive in this region, however well control is limited. Both resources-in-place and productivity may be higher or lower than current estimates.

BOEs may be misleading, particularly if used in isolation. A BOE conversion ratio of 6 Mcf: 1 bbl is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead. Given the value ratio based on the current price of crude oil as compared to natural gas is significantly different from the energy equivalency of 6 Mcf: 1 bbl, utilizing a conversion ratio at 6 Mcf: 1 bbl may be misleading as an indication of value. Mcfes may be misleading, particularly if used in isolation. A Mcfe conversion ratio of 1 bbl: 6 Mcf is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead. Given the value ratio based on the current price of natural gas as compared to crude oil is significantly different from the energy equivalency of 1 bbl: 6 Mcf, utilizing a conversion ratio at 1 bbl: 6 Mcf may be misleading as an indication of value.

The estimated values of future net revenue disclosed in this presentation, whether calculated with or without a discount rate, do not represent fair market value. 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 of aggregation. Estimates of reserves for individual properties may not reflect the same confidence level as estimates of reserves for all properties due to the effects of aggregation.

Painted Pony’s total working interest reserves, Contingent Resources and Prospective Resources are before royalties owned by others. The estimated future net revenues are stated before deducting income taxes and future estimated site restoration costs, and are reduced for estimated future abandonment costs and estimated capital for future development associated with the contingent resources. It should not be assumed that the undiscounted and discounted net present values represent the fair market value of the contingent resources and Prospective Resources.

In this presentation, information has been provided with respect to certain production information for lands and wells which is "analogous information" as defined applicable securities laws. This analogous information is derived from publicly available information sources which Painted Pony believes are predominantly independent in nature. Some of this data may not have been prepared by qualified reserves evaluators or auditors and the preparation of any estimates may not be in strict accordance with Canadian Oil & Gas Evaluation Handbook. Regardless, estimates by engineering and geo-technical practitioners may vary and the differences may be significant. Painted Pony believes that the provision of this analogous information is relevant to Painted Pony's activities, given its acreage position and operations (either ongoing or planned) in the area in question, however, readers are cautioned that there is no certainty that any of the development on Painted Pony's properties will be successful to the extent in which operations on the lands in which the analogous historical production information is derived from were successful, or at all.

The well test results disclosed in this presentation represent short-term results, which may not necessarily be indicative of long-term well performance or ultimate hydrocarbon recovery therefrom. In this presentation, “working interest” reserves are calculated as the Company’s share of reserves, excluding royalty interest reserves and before the deduction of royalty burdens payable. The reserves report was prepared utilizing definitions as set out under NI 51-101 – Standards of Disclosure for Oil and Gas Activities.