painted pony petroleum l tsx: td...

Investor

Presentation

PAINTED PONY

PETROLEUM LTD.TSX: PPY

April 7,

2016

1

“Why” do we do what we do?

Innovation

Win / Win Relationships

Antifragile

Long-Term Thinking

‘Always do the right

thing’

PPY embraces new ideas and technologies. It is in our DNA, it is part of who we are

Approaching all dealings with partners, shareholders, suppliers, and stakeholders with the goal of mutual benefit

“Antifragility is beyond resilience or robustness. The resilient resists shocks and stays the same; the antifragile gets better” – Nassim Nicholas Taleb (from “Antifragile: Things That Gain From Disorder)

PPY believes in the long-term view. This is why we have a 5-Year and a 30-Year plan

The PPY approach to business on all fronts is anchored by this simple but uncompromising principle

2(1) Average Daily Field-Estimate Production Volumes for three months ended March 31,2016

(2) As at December 31, 2015

(3) Comprised of bank debt and working capital deficiency; As at December 31, 2015

Corporate Profile

99MMcfe/day (16,500 boe/d)

Average Daily

Production (1)

TSX Ticker

Symbol PPY

Shares

Outstanding (2) 100million

Daily Trading

Volume(30 day average )

1.3million shares per day

Market

Capitalization$450million

Debt (3)$68.3million

Two-Year

Credit Facility($225 million currently, staged

increases to $325 million by

Oct. 31, 2016, Maturity

May 2017)

$325million

3

Asset FocusMontney

Asset100% BC Focused Montney

Montney is one of the most prolific and economic natural gas and liquids plays

4.6 Tcfe (768 MMboe) Proved Plus Probable Reserves(1) (4.2 Tcf Natural Gas;

76 MMbbl liquids)

Strategic AdvantagesHighly over-pressured, delineated, and tested Montney asset

West of BC Royalty Line (larger royalty credit per well)

Current and proposed sales pipelines intersect PPY properties

Incremental firm transportation in November 2016 expected to total 266 MMcf/d with

130 MMcf/d of incremental firm transportation directly into AECO in November 2017

GrowthForecasting exit production Q4 2016 at over 240 MMcfe/d (40,000 boe/d)

Fully funded with funds flow from operations and 2-year, $325 million, syndicated bank

credit facilities

Average Natural Gas Liquids production projected to grow by over 500% by end of 2017

(1) As at December 31, 2015; see Disclaimer Section

4

$41

$69

Note: GJ converted to Mcf at 1.15

$3.29 $3.31 $3.31$3.30 $3.30

$3.31 $3.37 $3.37

$2.09 $2.09

$2.09$2.09 $2.09

64% 66% 52%

62%68%

55%49% 36%

0

50

100

150

200

250

300

350

Q1 2016 Q2 2016 Q3 2016 Q4 2016 Q1 2017 Q2 2017 Q3 2017 Q4 2017

Fore

cast

ed N

atu

ral G

as P

rod

uct

ion

(M

Mcf

/d)

AECO Fixed Price Hedges ($/Mcf)Station 2 Fixed Price Hedges ($/Mcf)Unhedged

Prudent Risk ManagementFinancial Hedges

Together, financial hedges and physical contracts protect funds flow and mitigate pricing volatility thereby reducing the impact of regional pricing disparities

Well-Hedged for Current and

Forecast Production

5

PPY’s Montney Sweet Spot is:

• a dolomitic siltstone with higher quality

reservoir than a shale

• 4x thicker than the Marcellus at greater than

300 meters (approximately 1,000 ft.) thick

• a continuous sweet natural gas-saturated

zone with no associated or underlying water

• in a 1.8x over-pressured area

• a high heat-content natural gas play with

value enhancing associated natural gas

liquids up to 60 bbls/MMcf

• a commercially proven play with three distinct

layers currently producing with eventual 5 or 6

layers of potential under full exploitation

• positioned with excellent pipeline egress to

North American markets

300m(984 ft)

Thick, over-pressured, sweet spot

The Montney TrendLocation, Location, Location

6

(1) See “Disclaimer” section.(2) Based on fourth quarter 2015 annualized production(3) NAV calculated using the NPV10 of 2P reserves as prepared by GLJ Petroleum Consultants effective December 31, 2015, plus undeveloped land evaluated by Seaton-Jordan & Associates

Ltd., less bank debt and working capital deficiency, NAV Per Share calculated using fully diluted shares outstanding as of December 31, 2015.(4) FDC – Future Development Capital is capital necessary to develop those reserves deemed Undeveloped

2015 ReservesDeep, Long-Term, Underlying Value

4.6 Tcfe2P Reserves

December 31, 2015 (1)

57%per share

Increase in 2P

ReservesDecember 31, 2015 (1)

33% (to 8.8 Bcfe)Increase in 2P

Undeveloped

Reserves per well

$0.162P F&D per Mcfe (including change in FDC)

140 years2P Reserve

Life Index(2)

61 years1P Reserve

Life Index(2)

7.5 times2015 2PRecycle Ratio (F&D)

1.5 times2015 1PRecycle Ratio (F&D)

5,009% 2015 2P Production Replacement

$1.4 billion NPV10 Proved (Dec 31, 2015) (1)

$2.9 billion NPV10 2P Reserves (Dec. 31, 2015) (1)

$3.1 billion Net Asset Value (NAV)(3)

$28.81 NAV Per Fully Diluted Share(3)

3,857% 2015 1P Production Replacement

175%per shareIncrease in 1P

Reserves December 31, 2015 (1)

2.0 Tcfe1P Reserves

December 31, 2015 (1)

7

(1) FDC – Future Development Capital is capital necessary to develop those reserves deemed Undeveloped Source: TD SecuritiesPublic Companies Only; Canadian Assets

4.2 TCF

0

2

4

6

8

10

CNQ TOU ECA PPY PEY BIR ARX VII AAV BNP ERF PGF CR NVA BXE VET CQE TET KEL CPG BTE PNE PMT WCP LTS DEE IKM BNE RMP

2015 Cost of Supply

33% Increase in 2P Undeveloped Reserves per well

7.5x Recycle Ratio ($1.23 Netback / $0.16 F&D)

$1.48 2013 FDC/Mcfe (1)

$1.13 2014 FDC/Mcfe (1)

$0.75 2015 FDC/Mcfe (1)

Can

adia

n N

atu

ral G

as 2

P R

eser

ves

(Tcf

)Canadian Natural Gas 2P ReservesAs at Dec 31, 2015

49% Reduction in FDC/Mcfe

(‘13-’15)

4th Largest 2P Natural Gas

Reserves

8

• 147% Compound Annual Growth in reserves, 2007 – 2015

• 95% Compound Annual Growth in reserves per share, 2007 – 2015

337

431

0.0 0.2 0.10.6

2.02.2

3.3

4.9

7.7(46.1 Mcfe/sh)

0.0 0.10.3

0.20.5 0.5 0.7

1.2

3.4

0

1

2

3

4

5

6

7

8

9

0

100

200

300

400

500

600

700

800

900

2007 2008 2009 2010 2011 2012 2013 2014 2015

Res

erve

s (B

oe/

Shar

e)

Res

erve

s (M

Mb

oe)

Proved Reserves

Probable Reserves

2P Reserves per Share

1P Reserves per Share

Assuming Enterprise Value @ $5.18/sh

($4.50/sh equity + $0.68/sh net debt)

$5.18/sh

7.7 boe/sh(46.1 Mcfe/sh)

=$0.67 / boe

or

$0.11 / Mcfe

4.6 Tcfe (2P)

2.0 Tcfe (1P)

Reserves Growth Impressive and Consistent

Reserves Growth Per Share Growth Comparison

7.7

3.4

4.6

0.90.1

1.9

0.6

3.0

3.7

1.2

1.81.6

3.0

2.01.8

0.5

1.1

0.7 0.3

4.5

2.8

3.9

0.70.1

1.7

0.5

2.8

3.5

1.1

1.71.5

3.1

2.1 2.0

0.6

1.21.0

0.4

69%

22%18%

15%13%

10% 10% 8% 7% 7% 5% 5%

-4%-6%

-9% -10% -12%

-25%

-39%

-60%

-40%

-20%

0%

20%

40%

60%

80%

0

1

2

3

4

5

6

7

8

9

PPY BIR TOU KEL CKE AAV CQE VII PEY TET CR NVA POU ARX BNP YGR BXE LRE DEE

2015 BOE per 1,000 Shares

2014 BOE per 1,000 Shares

2P Reserves per Share Growth (2015 over 2014)

BO

E p

er 1

,00

0 s

har

es

2P

Res

erve

s p

er S

har

e G

row

th

PPY’s 2P reserves growth per share is the highest among gas-weighted names

Source: Dundee Capital Markets 9

10

60

123

337

230

366

431

3.3

4.9

7.7

0.7

1.2

3.4

0

1

2

3

4

5

6

7

8

9

0

150

300

450

600

750

900

2013 2014 2015

Res

erve

s/Sh

are

(Bo

e /

Shar

e at

YE)

Res

erve

s (M

Mb

oe)

Proved ReservesProbable Reserves2P Reserves per Share1P Reserves per Share

$2.77

$1.95

$1.60

$2.26

$1.35

$0.76

$1.38

$0.84

$0.16

$0.00

$0.50

$1.00

$1.50

$2.00

$2.50

$3.00

Proved Developed Producing Proved Proved Plus Probable

2013

2014

2015

-90%

-57%

-50%

PPY’s reserves per share continues to increase while cost of supply per Mcfe continues to

decline

+134% Increase in

2P Reserves per share

+403% Increase in 1P Reserve per share

Reserve Growth

Finding & Development

Costs

F&D

Co

st (

incl

chan

ge in

FD

C)

per

Mcf

e

Reserves Growth / Cost Reduction Bigger and Cheaper

Large contiguous land base with year-round access

• 217 Net sections (139,049 net acres)

• 2nd Largest position in northern Montney west of reduced

royalty line

High working interest

• Average 75%, with operatorship on all key properties

Attractive B.C. provincial royalty structure

• $2.2 million average royalty credit per well

• Only 3% royalty during royalty credit period

Top decile average peak rates for Montney

• 94 gross wells drilled (76 operated by PPY) as at March

31, 2016

• 183 net locations in 4-year plan

• Average 2P booking per undeveloped well of 8.8 bcfe

High gas liquids (C3+) content

• Average 60 bbls/MMcf forecast yield at Townsend

• 1,100 Btu/scf residual heat content

11

PPY Lands

Petronas Lands

Shell Canada Lands

Royalty Line

Major Gas Pipelines

Alaska Highway

All PPY Land West of

Royalty Line

Land PositionPremium Assets in the Optimum Location

12

PPY Blair-Daiber Type-Curve Comparison of Royalty Effect on Economics

British ColumbiaAlberta (2016)

Qualifying Deep Well WEST of ‘Royalty Line’

(PPY)

QualifyingDeep Well

EAST of ‘Royalty Line’

Shallow Well (<1,900 m TVD)

QualifyingDeep Well

NPV10 BT $7.7 mm $6.8 mm $6.6 mm $4.7 mm

Minimum Royalty Rate

3% 3% 3% 5%

Royalty Credit $2.2 mm $0.8 mm $0.7 mm $0.6 mm

Pay Out Period 21 months 21 months 22 months 28 months

IRR 63% 58% 56% 41%

• Painted Pony is 100% in B.C. and 100% west of the Deep Royalty Line

• Inclusive of the ‘B.C. Deep Well Royalty Credit’, B.C. has the best royalty structure in North America

*Based on strip pricing at March 29, 2016; see slide 27 and 29 for pricing

PPY’s Wells Instantly Worth

More Due to Location West of

Deep Royalty Line

Royalty AdvantageBest Royalty Structure in North America!

13

• Firm capacity on Spectra’s T-North

pipeline of 266 MMcf/d in November 2016

• Under terms of expanded firm capacity

agreement, PPY volumes can be sold at

either Station 2 or at Sunset Creek

• Sunset Creek tied directly into AECO

• 130 MMcf/d firm transportation onto AECO

starting November 2017

• Expanded firm capacity:

• allows for longer-term direct-

to-sales contracts

• Expanded firm capacity

contracts will meet

approximately 84% of

anticipated 2017 fourth

quarter natural gas volumes

PPY Lands

Station

Processing Facility

Proposed Meter Station

Royalty Line

SPECTRA Pipelines

TCPL Pipelines

TCPL Proposed North

Montney Mainline Project

Alliance Pipelines

B.C

.

Alb

erta

Firm Capacity and Diversified Sales Points to

AECO or Station 2

Sales Egress OptionalityFirm Transportation Supports Increasing Production Volumes

14

Blair

Cypress

Townsend

Daiber

PPY Montney Lands

New AltaGas Townsend Facility:

• Major new shallow-cut facility

• 198 MMcf/d gross capacity

• PPY has secured firm capacity for entire plant

• Expected completion in mid-2016

• 85% complete April 1, 2016

• PPY liquids production estimated to increase

over 540% over next 2 years

Additional Townsend Area Facilities

• Potential for additional facilities which could

be built on same site planned for 2018

Alaska Highway

FacilitiesKey Infrastructure

AltaGas Townsend

Facility 85% Complete

(198 MMcf/d)

Existing AltaGas Blair Creek Plant (80mmcf/d)

PPY Operated West Blair

(25 MMcf/d)

PPY Operated

Daiber (50 MMcf/d)

15

• Expect mid-year 2016 completion (approximately 85% complete as at April 2, 2016)

• PPY budget assumes September commissioning

AltaGas Townsend Facility: April 2, 2016

AltaGas Townsend Facility Construction Ahead of Schedule, Under Budget

Liquids-Rich Natural Gas Processing• Provides for the development of essential liquids-rich gas processing

facilities

Market-Competitive Product Pricing• AltaGas commits to seeking transactions at sales prices greater than

comparable area third party marketers

PPY Becomes AltaGas’ Primary Export Supplier• PPY receives preferred access to delivering gas on export contracts

which flow through AltaGas operated facilities

• AltaGas recently announced plans to build a propane export terminal at Ridley Island, British Columbia (FID decision anticipated in 2016)

• PPY will have preferred access to supply a portion of liquids to export facility

Flexibility to Develop and Process Lean Gas• Allows PPY to independently build lean gas processing facility

16

AltaGas is PPY’s Primary Natural Gas and NGL Marketer

Existing AltaGas PNG Mainline 10”

Planned access to both B.C. and Alberta Natural

Gas Sales Systems

Potential NGL + LPG Export

Opportunity from Washington via

ALA-PetroGasat Ferndale

New AltaGas

Proposed Propane Export

Terminal

AltaGas Strategic AllianceDeal with People You Trust in a Win / Win Alliance

17

761 1,553 2,8494,220

6,589

8,693

13,192

15,604

23,000

48,000

23

44 61

71

93 98

157 145

230

475

0

50

100

150

200

250

300

350

400

450

500

0

5,000

10,000

15,000

20,000

25,000

30,000

35,000

40,000

45,000

50,000

2008 2009 2010 2011 2012 2013 2014 2015 2016F 2017F

An

nu

al A

vera

ge B

oe

per

Day

per

1 M

illio

n S

har

es

An

nu

al A

vera

ge D

aily

Pro

du

ctio

n (

Bo

e /

day

)

• 156% Compound Annual Growth in production, 2007 – 2015

• 32% Compound Annual Growth in production per share, 2007 - 2015

Annual Average Daily Production per 1 Million Weighted-Average SharesOil & NGLsNatural GasQ4 2016 Exit Production

Q4 201640,000 Boe/d Forecast Exit

Production Growth Impressive and Consistent

18

0

20

40

60

80

100

120

140

0

1

2

3

4

5

6

7

1 2 3 4 5 6 7 8 910 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44

Wel

l Co

un

t

20

13

-20

14

Ave

rage

Pea

k M

on

th R

ate

(M

Mcf

/d)

Operator Rank

Average 3.1 MMcf/d

Painted Pony (6.2 MMcf/d)

Painted Pony Average Peak Month Rate Twice Average Comparable Wells

Source: geoSCOUT

275

PPY Wells Average Double the Rates of All

Wells in the Montney

Well PerformanceTop Performing Wells Among Montney Producers

19

Other PPY Operated Pads

Blair

West Blair

Cypress

Townsend

Daiber

2016 Active Pads

2016 Forecast

$179 million* Anticipated capital investment

25.0 Total net drills

30.0 Total net completions

Spectra Pipeline

Blair/Townsend Interconnect

Pipeline

AlaskaHi-way

In 2016, PPY expects to:

• Drill 7 net wells and complete 14 net wells at Townsend

• Drill 18 net wells and complete 16 net wells at Blair-Daiber

As of March 31, 2016:

• 12 net wells drilled

• 9 net wells completed

* Based on DC&E costs of $4.8 million per well

Capital Expenditures2016

16

15,604 23,000 48,000Average Daily Production (boe/d)

208% increase

94 138 288Average Daily Production (MMcfe/d)

208% increase

826 2,300 5,300Average NGL Production (bbls/d)

542% increase

15 25 47 Net Wells Drilled

-

10,000

20,000

30,000

40,000

50,000

60,000

Jan-1

5

Jul-1

5

Jan-1

6

Jul-1

6

Jan-1

7

Jul-1

7

Jan-1

8

Jul-1

8

Jan-1

9

Jul-1

9

Pro

du

ctio

n (

Bo

e p

er d

ay)

2019

2017

2016

2015

Base

2017

20

3-Year Development ModelImproved Well Performance Drives Down Well Count

350

300

250

200

150

100

50

Cu

mu

lati

ve w

ell c

ou

nt

Improved well performance has reduced the number of wells necessary to meet production targets from 105 net wells to 87 net wells, a 17% decrease

105 net wells2015 3-Year Model


Liquids production

forecasted to increase over

540% over next three years

2015 Actual 2016 2017

1st AltaGas Townsend

Facility (48 MMcf/d)

1st AltaGas Townsend

Facility (150 MMcf/d)

21

$2.73

$2.19$1.92

$1.14

$0.67$0.00

$1.00

$2.00

$3.00

2013 2014 2015 2016f 2017f

General & Administrative Costs per Boe

$9.17

$7.64

$5.61$4.59

$3.89

$0.00

$2.50

$5.00

$7.50

$10.00

2013 2014 2015 2016f 2017f

Operating Costs per Boe

Painted Pony’s Five-Year Plan will push cash costs lower through increased production volumes and operating efficiencies

Focus on one large property results in efficiencies of operations and staff

Operating costs will decline over coming years as production volumes increase, resulting in increased field netbacks

Per accounting standards, the capital lease fee for the AltaGas Townsend Facility is expected to be: $12 mm in 2016; and $48 mm in 2017 and is not reflected in operating costs for 2016 and 2017

G&

AC

ost

($

/ b

oe)

Op

erat

ing

Co

st (

$ /

bo

e)

Cost-Conscious CultureDriving Cash Costs Lower

22

$12

$12

$48

$91

$59

$91

$395

$614

$706

$466

$332

$483

$191

$299

$59

Capital Lease Fee

Development ModelFurther Capital Program Reductions

$48

Fore

cast

Ave

rage

An

nu

al D

aily

Pro

du

ctio

n (

Bo

e/d

)Free Funds Flow

$287

$435

$647

$523

$179

$284

$407

$304

$62

$181

$314

$497

23,000

48,000

72,000

102,000

0

20,000

40,000

60,000

80,000

100,000

120,000

$0

$100

$200

$300

$400

$500

$600

$700

2016 2017 2018 2019

Capital Program (March 2015)

Capital Program (March 2016)

Funds Flow (Based on March 2016 Strip Pricing)

Annual Average Daily Production (Boe/d)

-36% Reduction

-31% Reduction

-34% Reduction

-36% Reduction

$ (

mill

ion

s)

Strip pricing at March 29, 2016, please see slides 27 or 29 for pricing.

$102

$102 Million Free Funds Flow

in 2019

$700 million (37%) capital program reduction from

$1.9 billion to $1.2 billion with unchanged

production profile

$153$157

$130

$121

$60

$162

$212

$234

22,000

41,000

47,000 47,000

0

10,000

20,000

30,000

40,000

50,000

$0

$50

$100

$150

$200

$250

$300

2016 2017 2018 2019

Capital ($ millions) Funds Flow ($ millions) Production (boe/d) Free Funds Flow ($ millions)

$165 $169

23

An

nu

al Average D

aily Pro

du

ction

(bo

e/d)

$34

Strip pricing at March 29, 2016, please see slides 27 or 29 for pricing.

$212

$234

$48

$12

Capital Fee for Townsend Plant ($ millions)

$0.6 Billion Capital Spending Reduced by

$0.6 Billion (50%) from $1.2 Billion Growth Capital Plan on Strip

Pricing

Sustainability CaseBecause you asked “what if…?”

$48

$48

$178$65

$205

Free Funds Flow

$ (

mill

ion

s)

24Per accounting standards, the capital lease fee for the AltaGas Townsend Facility is expected to be: $12 mm in 2016; $48 mm in 2017; $59 mm in 2018; $91 mm in 2019 and is reflected in cash flow for purposes of the debt to cash flow ratio; strip pricing at March 29, 2016, please see slides 27 or 29 for pricing.

1.9x

1.5x

1.1x

0.5x

2.0x

1.2x

0.8x

0.2x

0.0

0.5

1.0

1.5

2.0

2.5

3.0

3.5

2016 2017 2018 2019

$3.25 Natural Gas NYMEX (WTI and FX at March 29th, 2016 Strip)

2.3x

1.9x

1.6x

1.0x

2.6x

1.5x

1.2x

0.6x

0.0

0.5

1.0

1.5

2.0

2.5

3.0

3.5

2016 2017 2018 2019

March 29, 2016 Strip Pricing

YE N

et D

ebt

: Q4

An

nu

aliz

ed F

un

ds

Flo

w

2.6x2.7x

3.2x

2.6x2.8x

2.0x

2.7x

2.3x

0.0

0.5

1.0

1.5

2.0

2.5

3.0

3.5

2016 2017 2018 2019

$2.25 Natural Gas NYMEX(WTI and FX at March 29th, 2016 Strip)

Balance sheet leverage provides production volume growth at full-cycle costs which provide strong economic returns despite lower commodity prices

Prudent LeverageBalance Sheet Strength Maintained

Development Case

Sustainability CaseDevelopment Case

Sustainability Case

Development Case

Sustainability Case

25

300-350 m

Inter-well

Spacing

~ 90-100 m Average

Fracture Stage Spacing

Ball-Drop

Packer

Surface Pad

Individual

Stage

Stimulation

Envelop

2016 Drilling

Activity are all

Parallel-Pairs

44-C

41-F

11-F

2-J

5-K

Blair

Daiber

Townsend

WestBlair

14-F

Production Increase at

No Cost Increase

TechnologyParallel-Pair Completion Using Open Hole Ball-Drop

0

2

4

6

8

10

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18

Pro

du

cin

g R

ate

(MM

cfe/

d)

Production Month

226

Blair-Daiber Well Economics

NPV10 BT* $7.7 million

IRR* 63%

Drilling $2.2 million

Completion $2.0 million

Equipping $0.6 million

Total Well Cost $4.8 million*Based on strip pricing at March 29, 2016; see slide 27 and 29 for pricing

• A 72% increase in 6-month cumulative production (1.4 Bcfe vs. 0.8 Bcfe) has significantly increased capital efficiencies and coupled with a capital cost decrease of 31%, has boosted economic returns despite a lower price forecast

All Perf & Plug (37 wells) 7.5 Bcfe Type Curve

Single Well Ball-Drop (7 wells) 11 Bcfe Type Curve

Parallel Pairs (10 wells) 15.5 Bcfe Type Curve

Cu

mu

lati

ve P

rod

uct

ion

(M

mcf

e)

Cu

mu

lative Net O

peratin

g Inco

me ($

M)

$0

$2,000

$4,000

$6,000

0

1,000

2,000

3,000

4,000

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18

Cumulative Volume (Mmcfe)

Cumulative Net Operating Income ($M)

Production Month

15.5 Bcfe EUR and Only 35% Initial Decline

Dramatic Increase in Capital Efficiencies Blair-Daiber – High-Rate, Liquids-Enhanced

15.5 Bcfe Type Curve

27

Plan to drill 18 net wells and complete 16 net wells in 2016

Development Program Economics

$4.8 million Drill, Complete, Equip & Tie-in

9.1 MMcfe/d IP30 Production Rate

15.5 Bcfe 2P Reserves per well

15 bbls/MMcf Liquids Recovery (C3+)

$7.7 million NPV per well @ 10% (BT)

63% IRR

21 months Payout Period

Strip Pricing at March 29, 2016

Year AECO WTI F/X($CAD/mcf) ($USD/bbl) ($CAD/USD)

2016 $2.02 $41.23 1.3062017 $3.04 $44.28 1.3042018 $3.20 $46.28 1.2992019 $3.37 $47.76 1.2932020 $3.55 $48.93 1.287

Blair

West

Blair

Cypress

Spectra Pipeline

Alaska Highway

Townsend

Daiber

Alliance Pipeline5 miles>>

Nov. 5 2014 Purchase

2016 Development Plan & EconomicsBlair-Daiber – High-Rate, Liquids-Enhanced


28

0

2

4

6

8

10

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18

Pro

du

cin

g R

ate

(MM

cfe/

d)

Production Month

9.5 Bcfe Type Curve – Ball Drop (8 wells)

Perf & Plug (2 wells)

• A 100% increase in 6-month cumulative production (1.0 Bcfe vs. 0.5 Bcfe) has significantly increased capital efficiencies and coupled with a capital cost decrease of 31%, has boosted economic returns despite a lower price forecast

• Parallel Pairs type-curve results pending

$0

$2,000

$4,000

$6,000

0

1,000

2,000

3,000

4,000

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18

Cumulative Volume (Mmcf)

Cumulative Net Operating Income ($M)

Cu

mu

lati

ve P

rod

uct

ion

(M

mcf

e)

Cu

mu

lative Net O

peratin

g Inco

me ($

M)

Production Month

*Based on strip pricing at March 29, 2016; see slide 27 and 29 for pricing

Through Technology, Doubled Bcfe

Recovered in First 6 Months

Improving Capital EfficienciesTownsend – Liquids-Rich Sweet Spot

Townsend Well Economics

NPV10 BT* $5.7 million

IRR* 54%

Drilling $2.2 million

Completion $2.0 million

Equipping $0.6 million

Total Well Cost $4.8 million

9.5 Bcfe Type Curve

29

Plan to drill 7 net wells and complete 14 net wells in 2016

Development Program Economics

$4.8 million Drill, Complete, Equip & Tie-in

7.4 MMcfe/d IP30 Production Rate

9.5 Bcfe 2P Reserves per well

60 bbls/MMcf Liquids Recovery (C3+)

$5.7 million NPV per well @ 10% (BT)

54% IRR

23 months Payout Period

Strip Pricing at March 29, 2016

Year AECO WTI F/X($CAD/mcf) ($USD/bbl) ($CAD/USD)

2016 $2.02 $41.23 1.3062017 $3.04 $44.28 1.3042018 $3.20 $46.28 1.2992019 $3.37 $47.76 1.2932020 $3.55 $48.93 1.287

Blair

West

Blair

Cypress

Spectra Pipeline

Alaska Highway

Townsend

Daiber

Alliance Pipeline5 miles>>

Nov. 5 2014 Purchase

2016 Development Plan & EconomicsTownsend – Liquids-Rich Sweet Spot


0%

25%

50%

75%

100%

125%

150%

$2.00 $2.25 $2.50 $2.75 $3.00

30

Townsend60 bbls/MMcf(9.5 Bcfe Single Well Ball-Drop Type Well)

Blair-Daiber15 bbls/MMcf(15.5 Bcfe Paired Parallel Type Well)

*Based on WTI and F/X at strip pricing as at March 29, 2016; see slides 27 or 29 for pricing

High-Rate and Liquids-Enhanced, Blair-Daiber

Wells Deliver Significant Torque to Stronger Gas

Prices

Stronger Liquids Pricing Boost Returns from Liquids-Rich

Townsend Wells

Development EconomicsPrice Sensitivity

31

Focused Resource

Processing Capacity to Support Growth

Firm Transportation

Lowest Royalty Framework

Low Well Costs

Top Well Performance

Well Hedged

Rapid Growth

Deep Drilling Inventory

Liquids-Rich

Financing In Place

“Best Pony in the Race”Checking Off All of the Boxes

Appendices and Disclosures

32

Proposed LNG Projects Capacity

Exxon – ImperialWCC LNG

~4.0 Bcf/d

Shell – Petrochina, Mitsubishi, KOGASLNG Canada

~3.2 Bcf/d

Nexen / CNOOC – Inpex, JGCAurora Liquefied Natural Gas Ltd.

~3.1 Bcf/d

Petronas – JapexPacific Northwest LNG

~2.6 Bcf/d

Kitsault Energy Ltd.Kitsault Energy Ltd. (Private)

~2.6 Bcf/d

Veresen IncJordan Cove LNG

~1.4 Bcf/d

Chevron – ApacheKM LNG

~1.3 Bcf/d

Pacific Oil & GasWoodfibre LNG

~0.3 Bcf/d

Total Filed Application Capacity (NEB)

~18.5 Bcf/d

PNG Mainline

10”

ChevronApproved Pipeline

42”

Proposed TransCanada

Petronas

Spectra Mainline

36”and 30”

Proposed TransCanada Shell

42”

Proposed West Coast LNG Projects

33

16

15,604 23,000 48,000 72,000 102,000 Avg. Daily Production (boe/d)

94 138 288 432 612 Avg. Daily Production (Mmcfe/d)

826 2,300 5,300 7,800 12,000 Avg. NGL Production (bbls/d)

15 25 47 68 43 Net Wells Drilled

-

100

200

300

400

500

600

700

-

20,000

40,000

60,000

80,000

100,000

120,000

Jan-1

5

Jul-1

5

Jan-1

6

Jul-1

6

Jan-1

7

Jul-1

7

Jan-1

8

Jul-1

8

Jan-1

9

Jul-1

9

Pro

du

ctio

n, B

OE/

d

2019

2018

2017

2016

2015

Base




34

5-Year Development ModelImproved Well Performance Drives Down Well Count

The number of wells necessary to

achieve annual production volume

targets has decreased by 38% due to improved well performance

and design

38%1st AltaGas Townsend Facility

(150 MMcf/d)

1st AltaGas Townsend Facility

(48 MMcf/d)

2nd AltaGas Townsend Facility (150 MMcf/d)

2nd AltaGas Townsend Facility

(48 MMcf/d)

35

Institution Analyst

AltaCorp Capital Patrick O’Rourke

BMO Capital Markets Joe Levesque

Canaccord Genuity Corp. Anthony Petrucci

CIBC World Markets Adam Gill

Cormark Securities Inc. Garett Ursu

Credit Suisse Securities David Phung

Desjardins Capital Markets Jamie Kubik

FirstEnergy Capital Cody Kwong

GMP Securities Aaron Swanson

ITG Michael Charlton

National Bank Financial Dan Payne

Paradigm Capital Inc. Ken Lin

Raymond James Jeremy McCrea

RBC Capital Markets Michael Harvey

Scotiabank Global Banking & Markets Cameron Bean

TD Securities Juan Jarrah

Equity ResearchSell-Side Analyst Coverage

36

Auditor KPMG LLP

Evaluation Engineers GLJ Petroleum Consultants Ltd.

Banks The Toronto-Dominion Bank

The Bank of Nova Scotia

Alberta Treasury Branches

Canadian Imperial Bank of Commerce

HSBC Bank Canada

Wells Fargo Bank

Corporate Office

1800, 736 – 6th Avenue SW, Calgary, AB T2P 3T7

Toll Free Investor 1 (866) 975-0440

Tel (403) 475-0440 Fax (403) 238-1487

Email: [email protected]

www.paintedpony.ca

Corporate Overview

37

R: Reserves per share are calculated by dividing P+P reserves by shares outstanding at the end of the year. As at December 31, 2015, Painted Pony’s P+Preserves were 768 MMboe and there were 100.0 million shares outstanding. Also see “Note Regarding Reserves Disclosure” in “Disclaimer” section.

P: 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.2015 production averaged 15,604 boe/d and Painted Pony had 99.8 million weighted average shares during 2015. Amounts and estimates beyond 2015 arethose of Painted Pony’s management as of the date hereof. Also see “Disclaimer” section.

IRR: 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 cashflows from a particular investment or project equal to zero.

IRR, NPV and Payout Period are all pre-tax

Endnotes

This 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 quarter ended December31, 2015, 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 thepreparation of such information may prove to be incorrect.

Certain information regarding the Company set forth in this presentation, including statements regarding management’s assessment of the Company’s future plans and operations, the planning and development of certain prospects, productionestimates, 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), facilityexpansion 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 andnecessarily 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, industryconditions, 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, includingdrilling, 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 capitalfrom 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-lookingstatements, 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 theCompany’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 MD&A for the year ended December 31, 2015.

The forward-looking statements contained in this presentation 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 aresult 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. TheCompany 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 theassumptions on which such information is based. The Company does not assume any responsibility for the accuracy or completeness of such information.

This presentation also contains future-oriented financial information and financial outlook information (collectively, "FOFI") about prospective results of operations, future net revenue, share capital, cash flow, capital expenditures, net debt andcomponents 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 presentation was made as of the date of this presentation and wasprovided for the purpose of providing information about management's current expectations and plans relating to the future, including with respect to the Company’s ability to fund its expenditures. The Company disclaims any intention orobligation to update or revise any forward looking statements or FOFI contained in this presentation, whether as a result of new information, future events or otherwise, unless required pursuant to applicable securities law. Readers arecautioned that the forward looking statements and FOFI contained in this presentation should not be used for purposes other than for which it is disclosed herein. The forward looking statements and FOFI contained in this presentation areexpressly qualified by this cautionary statement.

NON-GAAP MEASURESThis presentation contains references to measures used in the oil and gas industry such as “cash flow” and “net debt’” These measures do not have any standardized meanings within International Financial Reporting Standards (“IFRS”) and,therefore, reported amounts may not be comparable to similarly titled measures reported by other companies. These measures have been described and presented in this presentation in order to provide shareholders and potential investorswith additional information regarding Painted Pony’s liquidity and its ability to generate funds to finance its operations. Cash flow should not be considered an alternative to, or more meaningful than, cash provided by operating, investing andfinancing activities or net earnings as determined in accordance with IFRS, as an indicator of Painted Pony’s performance or liquidity. Cash flow is used by Painted Pony to evaluate operating results and the Company’s ability to fund capitalexpenditures and repay debt. Painted Pony uses net debt as a measure to assess its financial position. Net debt includes current liabilities, including Painted Pony’s credit facility, less current assets excluding risk management contracts.

Included in this presentation are estimates of the Company's 2016-2019 cash flow which are based on various assumptions as to production levels, commodity prices and other assumptions, are provided for illustration only and are based onbudgets 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 inMarch 2016 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 beappropriate for other purposes.

38

Advisory

39

NOTE REGARDING RESERVES DISCLOSUREThe reserves and resources estimates contained herein, including the corresponding estimates of future net revenue, 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 ortechnology 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 regulatorymatters, 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 inaccordance with the level of certainty associated with the estimates and may be subclassified based on project maturity and/or characterized by their economic 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 anassociated 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 maybe subclassified based on project maturity.

"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, andengineering 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 andmay be subclassified based on development and production 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 inknown accumulations, prior to production, plus those estimated quantities in accumulations yet to be discovered (equivalent to “total resources”).

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 wellcontrol is limited. Both resources-in-place and productivity may be higher or lower than current estimates.

Boe 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 thewellhead. 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 anindication of value. Mcfe 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 valueequivalency 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 bemisleading 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 propertiesmay 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 asestimates 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 siterestoration 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 presentvalues 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 publiclyavailable 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 notbe in strict accordance with the 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 thisanalogous 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 thedevelopment 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 National Instrument51-101 – Standards of Disclosure for Oil and Gas Activities.

Advisory

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