Celebrating 10 Years of Growth

Investor Update

April 5, 2017

Win / Win Relationships

Long-Term Thinking

‘Always do the right thing’

Innovation

Antifragile

“Why” do we do what we do?

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

1

Net Debt (3) 228.5 million Shares Outstanding (2) 120million

Corporate Profile Stand Alone

Ticker Symbol PPY TSX

Daily Production(1)

220 MMcfe/day (36,695 boe/d)

Daily Trading Volume (30 day trading average)

1.6 million shares per day

Market Capitalization April 5, 2017

672million Syndicated Credit Facility 325 million

(1) Average production volumes during three months ended December 31, 2016 (2) As at April 5, 2017 (3) Comprised of bank debt and working capital deficiency (excluding Mark-to-Market Unrealized Hedging Gain/Losses); As at December 31, 2016 2

UGR Acquisition Overview Material Impact / Significant Value

drilling inventory providing increased exposure to the highly prolific Blair /

Daiber area rich in Montney gas and gas liquids

2P of 2.0 Tcfe and 1P of 0.8 Tcfe plus

Immediate access to 105 MMcf/d unutilized capacity

Reserves

Facilities

UGR Acquisition

Current production of approximately 51 MMcfe/d

(8,500 boe/d); plans to increase production by incremental 13 well

drilling program in 2017

Transportation 174 MMcf/d of incremental firm transportation supports growing

production base

Production

3

UGR Acquisition Overview Increased Scale Drives Down Cost, Consolidation Drives Control, Control Drives Opportunity!

Immediate 2017 Impact • 105 MMcf/d of immediately available, unused processing capacity

• Will add 70 MMcfe/d of incremental (drill ready) production volumes before year-end 2017

• 2P + 1P reserve adds lower than PPY’s industry leading FD&A costs

• Best metrics of any Montney acquisition in 5+ years

Land Impact • Glove-fit consolidation into PPY’s existing Montney acreage reducing loss acreage due to

edge effects and enhances development efficiency

• UGR’s 108 net sections combines with PPY to create a land base of 314 net Montney sections

• 20 sections held jointly immediately become 100% WI for PPY pushing average Montney WI to 94%

4

UGR Acquisition Overview Material Impact / Significant Value

Facilities Impact • 105 MMcf/d of UGR’s unused facility capacity is comparable in size to an additional processing train at the

Townsend Facility immediately without additional cost or construction time

• UGR total processing capacity of 155 MMcf/d is 64% owned (99 MMcf/d) and operated

Financial Impact • Anticipate increasing pro forma cash flow per share(1) by 89% from $0.56 in 2016 to $1.06 in 2017 and 67%

from $1.06 in 2017 to $1.77 in 2018

• Based on the pro forma combined PDP value, PPY’s credit facility anticipated to increase to $500 million(2)

Reserves Impact • Pro Forma 6.9 Tcfe (1.15 Bboe) of 2P reserves providing PPY with the third-largest both 1P + 2P natural gas

reserves in Canada among public companies

• Adds 197 net 2P drilling locations, which is expected to increase as the 2016 UGR reserve report is capital and infrastructure constrained

• PPY’s lower capital cost structure and development plans brings significant value forward by reducing the expected FDC on UGR lands by approximately $200 million

(1) Based on strip pricing at March 13, 2017 5 (2) Syndicated credit facility a combination of $400 million credit + $100 million development line

UGR Blair Creek Acquisition Overview

Transaction Summary: • On March 15th, 2017 PPY announced the acquisition of UGR

for $277 million (41 million PPY shares and assumption of $47 million of net debt(1))

• UGR is a pure play NEBC Montney producer with current production of 51 MMcfe/d (8,500 boe/d) based on field estimates Beg

• Accretive to cash flow in 2018 Q2

• UGR had estimated 1P reserves of 0.8 Tcfe and 2P reserves of 2.0 Tcfe at Dec 31, 2016 Blair

• UGR operates high working interest Montney assets with land holdings jointly with and adjacent to PPY’s assets

• UGR's asset base consists of 108 net sections • Blair/Daiber

• 25,363 net acres • 32 gross horizontal wells drilled • de-risked and development ready

Daiber

• Beg • 22,282 net acres • high liquids (30+ bbls/MMcf) with high gas rates

• Jedney • 21,498 net acres; • high liquids (30+ bbls/MMcf) • 3 UGR gross horizontal wells drilled

LEGEND Painted Pony Lands UGR Lands Joint Interest Lands PPY/UGR Painted Pony Facilities UGR / Third-Party Facilities Enbridge T-North Pipeline Secondary Pipelines

(1) Includes bank debt and $1 million of working capital deficiency as at December 31, 2016. 6

Significant Growth Pro Forma

Asset • 100% BC focused Montney

• 300m thick pay zone with reserves booked in three layers

• 314 net sections (201,009 net acres)

• 126 gross operated wells drilled pro-forma upon closing of transaction

• 6.9 Tcfe (1,148 MMboe) 2P Reserves(1) (2)

(6.4 Tcf Natural Gas; 81.3 MMbbl liquids)

Strategic Advantages • Attractive B.C. provincial royalty structure with $2.2 million average

royalty credit per well (only 3% royalty during royalty credit period)

• Current and proposed sales pipelines intersect PPY properties

• Firm transportation in-place to meet production growth targets

Strong Growth • Q4 Exit 2017 production expected to be approximately 75,000 boe/d or

450 MMcfe/d

• 2017 annual average daily production will increase 109% to 290 MMcfe/d (48,400 boe/d) from 2016 average annual daily production of 139 MMcfe/d (23,204 boe/d)

(1) Estimated as at December 31, 2016; see Advisories Section (2) Painted Pony 2016YE Reserves evaluated by GLJ Petroleum Consultants; UGR Blair Creek Ltd. 2016YE Reserves evaluated by McDaniel’s & Associates. The pro forma is the two engineering

reports added together. 7

Montney Sweet Spot Location, Location, Location

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 m (approximately 1,000 ft.) thick

• a continuous sweet natural gas-saturated zone with no associated or underlying water

• in a up to 1.8x over-pressured area

• high gas liquids (C3+) content with 1,170 btu/scf of residual heat content

• High liquids pro forma production at Townsend, Beg and Jedney

• a commercially proven play with three distinct layers currently producing with eventual 5 or 6 layers of potential under full exploitation

8

Painted Pony’s Gas Processing Complex Pro Forma Key Infrastructure

Total Pro Forma Processing Capacity UGR Owned

Jedney (13 MMcf/d)

• October 2017 – 565 MMcf/d

AltaGas Townsend Facility • AltaGas built shallow-cut facility currently processing PPY production

volumes PPY Operated West Blair

(13 MMcf/d)

AltaGas Blair Creek Plant (75 MMcf/d)

• PPY has secured firm capacity for entire plant on long-term contract

• Phase 1 – Currently flowing 150 MMcf/d of natural gas; additional 48 MMcf/d beginning in August 2017

• Phase 2 – 99 MMcf/d Phase 2 expansion expected to be completed by October 2017

PPY Operated Daiber

(50 MMcf/d)

Additional Facilities

Two UGR Owned Daiber

Facilities (60 MMcf/d)

• Kobes Facility

• 30 MMcf/d UGR-owned dry gas facility

• Daiber Facilities

• Three facilities: 110 MMcf/d dry gas facilities (60-C, 66-C, 44-C)

• Kanata: 27 MMcf/d refrigeration gas processing plant (54-C)

• AltaGas Blair Creek Facility

• 75 MMcf/d refrigeration gas processing plant

• West Blair Facility

• 13 MMcf/d dry gas facility

• Jedney

• 13 MMcf/d facility

Kanata Rich Gas

(27 MMcf/d)

LEGEND

UGR Owned Kobes

(30 MMcf/d) Painted Pony Lands UGR Lands Joint Interest Lands

AltaGas Townsend

Painted Pony / AltaGas Facilities UGR / Third-Party Facilities Enbridge T-North Pipeline Secondary Pipelines

Facility (198 MMcf/d total current capacity; expansion to

297 MMcf/d by Oct 2017)

9

8,693 6,589 boe/d boe/d

600

13,192 boe/d

15,604 boe/d

23,204 boe/d

84,800 boe/d

48,400 boe/d

Annual Average (boe/d )

350

Oil and NGL Natural Gas Pro Forma Production Growth

Production per Share Forecast Production per Share

Pro Forma Production Growth Pro Forma Per Share Growth

321

509

2018e Pro Forma

250% Organic Production Growth, 2012 - 2016 1,000+% Projected Production Growth, 2012 – 2018 450+% Projected Production / Share Growth, 2012 - 2018

191

2012 2013 2014 2015 2016 2017e Pro Forma

Annu

al Aver

age Da

ily Produ

ctio

n (MMcf

e/d)

10

300

250

200

150

100

50

0

Annual Average MMcfe per Day

per 1 Million Shares

40 52 79 94

139

94 87

56 59 139

290 300

200

100

0

500

400

Strong Per Share Metrics Pro Forma Cash Flow Growth

$0.55

$0.50

$0.45

$0.40

$0.35

$0.30

$0.25

$0.20

$0.15

$0.10

$0.05

$0.00 $0.10 $0.10

Significant Year-over-Year Growth in Pro Forma Cash Flow per Share

$0.29 2015

$0.06 $0.03 $0.08 $0.09

$0.56 2016

$0.13 $0.26 $0.28 $0.17

2017f $1.06

$0.23 $0.38 $0.45 $0.40

2018f $1.77

$0.43 $0.49

Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4

2015 2016 2017 Pro Forma 2018 Pro Forma Forecast Forecast

11

Top Well Performance – “The Sweet Spot” PPY and UGR

Based on cumulative

volumes, PPY & UGR have 11 of

the top 12 wells in the Northern

35 of top 100 wells are Montney PPY/UGR; and 38% of the 93 PPY/UGR wells

are in top decile!

6-Month Cumulative Montney Gas Production as of January 2017

Painted Pony UGR Other Producers

1,800,000

1,600,000

1,400,000

1,200,000

1,000,000

800,000

600,000

400,000 Cumu

lative

Nat

ural

Gas

(Mcf

)

200,000

0 Top 100 Wells - Northern Montney Field (sample set of 1,046 wells)

Source: GeoScout 12

2017 & 2018 Development Model Infrastructure Build Drives Growth (Pro Forma)

Townsend Facility (Phase 1A) 150 MMcf/d Commitment

AltaGas Townsend

Facility (Phase 1B) 48 MMcf/d Commitment

AltaGas AltaGas Townsend

Facility (Phase 2) 99 MMcf/d

80,000

UGR Production Post-Closing

2018

2017 20,000

10,000 2016 (base)

2016 109% Growth 2017(e) 75% Growth 2018(e)

Produc

tion Volum

es (boe/d)

70,000

60,000

50,000

40,000

30,000

100,000

90,000

Avg. Daily Production (boe/d) 23,204 48,400 (e) Avg. Daily Production

(MMcfe/d) 139.2 290 (e)

Avg. NGL Production (bbls/d) 1,557 4,000 (e)

84,800 (e)

509 (e)

6,300 (e) 13

Growth-Oriented Spending Strong Capital Discipline

Pro-Forma Annual Average Daily Production (Forecast)

Pro-Forma Cash Flow (Net of Interest Expense, G&A, and Capital Lease Finance Expense) (Based on March 13, 2017 Strip Pricing; see slide 24 for pricing)

$CAD

(M

illions)

$400

$350

$300

$250

$200

$150

$100

$50

$0

400

0

600

500

300

200

100

Annu

al

Aver

age Da

ily For

ecast Produc

tion (MMcfe/d)

509 MMcfe/d (84,800 boe/d)

$149 $301 $288

290 MMcfe/d (48,400 boe/d)

139 MMcfe/d (23,204 boe/d)

$56 $348 $204

Pro-Forma Capital Development Program Annual Average Daily Production (Actual)

Year-End Net Debt 2016 2017e 2018e

to Q4 Annualized

2.0x 1.5x 1.2x Cash Flow 14

Pro Forma Reserves PPY + UGR

PPY Pro Forma 1P Reserves

3.4 Tcfe PDP

Reserves 0.6 Tcfe

PPY Stand Alone 1P Reserves

2.7 Tcfe Probable Reserves 3.5 Tcfe

PUD + PDNP

UD + PDNP Reserves eserves 2.8 Tcfe PDP

Reserves 0.5 Tcfe

PUD + PDNP

Reserves 2.2 Tcfe

Probable Reserves 2.3 Tcfe

6.9 Tcfe 2P Reserves Pro Forma Reserves at Dec 31, 2016

4.9 Tcfe 2P Reserves PPY Stand Alone Reserves at Dec 31, 2016 15

Canadian Natural Gas 2P Reserves As at Dec 31, 2016

Proved Natural Gas Reserves Probable Natural Gas Reserves UGR Proved and Probable Natural Gas Reserves

10.0

0.0

6.4 Tcf

PPY’s 2P Natural Gas reserves of 4.5 Tcf

increase to pro forma 6.4 Tcf post-UGR closing; PPY will have the third-largest 2P natural gas reserves in

Canada

Cana

dian

Nat

ural

Gas

2P Reserves (Tcf)

8.0

6.0

4.0

2.0

TOU CNQ PPY ECA BIR VII PEY ARX AAV BNP CR PGF NVA KEL TET CPG SRX POU WCP PMT

Source: TD Securities and RBC Capital Markets; Public Companies Only; Canadian Natural Gas Assets 16

Pro Forma Reserve Growth Deep Value

40

0

50

30

20

10

Reserves per Share (Mcfe

per Share) Re

serv

es (Tcfe)

4

0

6

2

1.1 Tcfe

13.0

2.9

42.8 Mcfe/sh (7.1 Boe/sh)

($5.60/sh equity + $1.05/sh net debt)

$6.65/sh

Enterprise Value @ $6.65/sh

1.7 Tcfe

19.7

4.1

= $0.16/ 2P Mcfe ($0.94 / 2P Boe)

2.9 Tcfe

29.5

7.4

4.6 Tcfe

46.1

20.2

4.9 Tcfe

49.3

21.6

6.9 Tcfe

3.4 Tcfe

0.6 Tcfe

42.8

21.2

Reserves MMboe MMboe MMboe MMb

8

60

136.9 191.1 290.3 488.4 768.0 oe MMboe

2012 2013 2014 2015 2016 2016 Pro Forma

PDP Reserves 1P Reserves 2P 2P Reserves per Share 1P Reserves per Share

• 63% Compound Annual Growth in Reserves, 2012 – 2016 • 56% Compound Annual Growth in Reserves per Share, 2012 – 2016

* Net debt per share is pro forma (inclusive of $106 million net proceeds from the March 15, 2017 equity financing and assumption of $47 million of net debt from UGR) 17

Proved plus Probable Proved Developed Producing Proved

18 * Not meaningful as FDC reductions were greater than 2P capital expenditures, resulting in negative FD&A costs

Reserve Additions At Very Low FD&A Costs

Finding, Development & Acquisition Costs

$3.00

$2.50

$2.00

$1.50

$1.00

$0.50

$0.00

2013

$2.77 $2.76

2013

$1.95

$1.35

2014

$0.84

2015

$0.56

2016

$0.36

UGR

Acqu

isiti

on

$1.60

2013

$0.76

2014

4-Year 2P Average

$0.58/Mcfe

$0.16

2015

NMF*

2016

$0.14

ion

UGR

Acq

u isit

$2.26

2014

$1.38

2015

$0.72

2016

UGR Acqu

isiti

on

Industry leading 1P + 2P FD&A costs

-$0.50

FD&

A Costs (inc

l change in FDC

) per Mcfe

G&A Costs per Mcfe Operating Costs per Mcfe ** Liquids Production

Increasing Pro Forma Cash Flow per Mcfe Driving Costs Lower / Increasing Liquids Yields

2015 2016 2017f 2018f

G&A

Cos

t ($ / Mcf

e) $0.40

$0.30

$0.20

$0.10

$0.00

$0.32

$0.21

78% reduction

$0.16

$0.07

2015 2016 2017f 2018f

Oper

atin

g Co

st ($ / Mc

fe)

$1.00

$0.75

$0.50

$0.25

$0.00

$0.94

$0.68

$0.54

45% reduction

$0.52

2015 2016 2017f 2018f

Liqu

ids Pr

oduc

tion

(B

bls/d)

4,000

8,000

6,000

2,000

0 826

663% increase

1,557

3,900

6,300

2015 2016 2017f 2018f

*Based on strip pricing at March 13, 2017; see slide 26 for pricing ** Does not include capital lease costs 19

Cash Flow per Mcfe

$1.75

$1.50

$1.25

$1.00

$0.75

$0.50

$0.25

$0.00

$0.83

87% increase

$1.09

$1.40 $1.55

Cash

Flow Ne

tbac

k ($/Mcf

e)

Lower Cash Costs Combine with

Increasing Liquids Helps to Drive

Higher Cash Flow Netbacks

Cash Costs Non-Cash Costs Cash Costs Non-Cash Costs

$1.00

$0.50

$0.33

2018f

$3.14/Mcfe

$1.55/Mcfe Cash Flow

Capital Lease Expense Gains/Losses $0.00

$0.00

DD&A Non-cash Items

Note: Based on strip pricing at March 13, 2017 see slide 26 for details; *Pre-Tax Earnings (excluding mark-to-market unrealized hedging gains/losses)

$1.50

Pre-Tax Earnings

$0.67 Per Mcfe

$1.50

Pre-Tax Earnings

$0.56 per Mcfe

$1.00

$3.00

$2.50

$2.00

Royalties $0.07

OpEx $1.50

$1.00

$0.41 Capital Lease Expense

$0.00

Interest $0.50

Transportation

$0.54

$0.46

2017f

G&A $0.16 $0.10

$1.41/Mcfe Cash Flow

Transportation $0.44

Royalties $0.08

$0.52

G&A $0.07

Interest $0.07

OpEx

$3.50

$3.00

$2.50

$2.00

$1.50

$1.00

$0.50

2018f

Financial Hedging Gain $0.01

20

Top Line Revenue $3.07/Mcfe

$0.85 DD&A Non-cash Items

$0.50

$0.00

2017f

Financial Hedging

Top Line Revenue $3.50

$0.00

$0.88

Solid Margins Drive Earnings (Pro Forma) Positive Earnings Expected in 2017 and 2018

Pro Forma Financial Hedges Prudent Risk Management

Natural Gas Q1 2017e Q2 2017e Q3 2017e Q4 2017e Q1 2018e Q2 2018e Q3 2018e Q4 2018e

Production Percentage 73% 69% 76% 78% 51% 33% 26% 20% Hedged

Note: GJ converted to Mcf at 1.15 21

Expected A

vera

ge Nat

ural

Gas

Produ

ction

(MMcf/d)

450

400

500

350

300

250

200

150

100

50

0

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

$3.31

$2.44

$3.32

$3.31

$3.31

$2.42 $2.69

$3.40 $3.28 $3.28 $3.29

$2.09

$3.30

$2.23 $2.34 $3.31

$3.23

$2.68

Financial hedges, working together with index physical contracts, protect cash flow and mitigate pricing

volatility

$3.12

$3.31

$2.69

2017 Pricing Managing Volatility

86% of 2017 Production Volumes

Priced Outside Station 2 Spot

Total Production Revenue by Source

SUMAS 7%

Station 2 Spot 9%

91% of 2017 Production Revenue

Sourced Outside Station 2 Spot

Production Volumes Pricing Exposure

*Note: Does not include Pro Forma UGR Volumes 22

Pro Forma Firm Transportation Long-Term Strategy

CYPRESS

Kitimat

Enbridge Station CS2

BLAIR

DAIBER

JEDNEY

BEG

TOWNSEND

Aitken Creek

McMahon Gas Plant

Saturn Unit 1 & 2

CS16 Sunset Creek

PPY LANDS STATION PROCESSING FACILITY PROPOSED METER STATION ROYALTY LINE ENBRIDGE PIPELINE TCPL PIPELINES TCPL PROPOSED NORTH MONTNEY MAINLINE PROJECT ALLIANCE PIPELINES

CS1

Dawson

TCPL Groundbirch

Lateral

AECO

23

T-North to Station 2 / Sunset Creek

200 MMcf/d Current

105 MMcf/d at Closing of UGR Acquisition

180 MMcf/d Incremental Dec 2017

200 MMcf/d Incremental Nov 2018

685 MMcf/d as at Dec 2018

AECO (subset of T-North Firm Capacity) 45 MMcf/d Current 130 MMcf/d Incremental November 2017 (April 2018 Firm)

175 MMcf/d as at April 2018

SUMAS (subset of T-North Firm Capacity) 18 MMcf/d Current 6 MMcf/d Winter Only November 2017 9 MMcf/d Incremental April 2018

27 MMcf/d as at April 2018

Ample Firm Transportation Ensures Growing Volumes Reach Markets

2017 Economics By Area March 13, 2017 Strip Pricing

Op Day

Gas Rate (mmc

fe/d)

15

12

9

6

3

0

Townsend Management Type Curves

45 bbls/MMcf liquids

15

12

9

6

3

Op Day

Gas Rate (m

mcef

/d)

0

Daiber

Op Day

Gas Rat

e (mmc

f/d)

15

12

9

6

3

0

Management Type Curves

(up to 1,180 btu/scf)

Dry Gas High heat Content

Drilling $1.9mm Completions $2.1mm Equip / Tie-in $0.55mm

Capital Costs $4.55 mm/well

P90 20% $1.5

Strip Pricing at March 13, 2017

P90

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

2017 $3.15 $2.75 $50.17 1.337 2018 $3.04 $2.76 $50.60 1.333` 2019 $2.87 $2.55 $50.50 1.324 2020 $2.83 $2.47 $50.70 1.316

40% $4.5 P90

P90 wells at Daiber show excellent rate

of return

69% $6.2

24

Blair Management Type Curves

15 bbls/MMcf liquids

0 5 10 15

Cumulative Gas (bcfe) GLJP90 P LJ P5 P50 GLJ P10 P

0 5 10 15

Cumulative Gas (bcfe)

P90 LJ P LJ P5 P50 P10 LJ P

0 5 10 15

Cumulative Gas (bcf) LJ P9 P90 GLJ P50 P LJ P10 P1

Half-Cycle Economics Half-Cycle Economics Half-Cycle Economics

Townsend IRR NPV10 Blair IRR NPV10 Daiber IRR NPV10

P50 72% $5.8 P50 113% $8.4 P50 94% $7.6

P10 >200% $14.2 P10 >200% $14.4 P10 >200% $11.0

Development Economics Price Sensitivity (Half Cycle)

Rate

of

Retu

rn (BT

)

100%

75%

50%

Townsend wells

Stronger liquids pricing boost returns from liquids-rich

Townsend P50

Condensate, NGL and exposure to stronger Blair wells provide

natural gas pricing

Liquids-enhanced,

Blair P50 Daiber P50

High-rate Daiber wells provide natural gas

pricing torque

$2.25/MMbtu $2.50/MMbtu $2.75/MMbtu $3.00/MMbtu $3.25/MMbtu

125%

25%

0%

150%

NYMEX NYMEX NYMEX NYMEX NYMEX

*Based on WTI and F/X at strip pricing as at March 13, 2017; see slide 25 for pricing 25

Forecasted Capital Expenditures Pro Forma

2017 Pro-Forma Capital Spending Forecast

Period Capital Drilling Completions

Q1 $93 million (e) 22 wells (e) 12 completions (e)

Q2 $24 million (e) 8 wells (e) 2 completions (e)

Q3 $143 million (e) 25 wells (e) 34 completions (e)

Q4 $88 million (e) 16 wells (e) 16 completions (e)

Total $348* million (e) 71 net wells (e) 64 net completions (e)

*2017 Capital Budget based on DCT&E costs of $4.55 million per well *All wells are 100% PPY working interest pro-forma 26

“Pony Points” Checking Off All The Boxes

Financing In Place $228 mm drawn on $325 mm Facility; Pro Forma $500 mm facility Top Well Performance 9 Bcfe EUR per Well Low Well Costs $4.55 mm per well (DCE&T) Well Hedged 75% Hedged 2017; 37% Hedged 2018 Pro Forma Rapid Growth estimated production growth of 80% 2016 to 2017 (109% Pro Forma) Lowest Royalty Framework Less than 3% royalty Processing Capacity Supports Growth Significant Firm Processing In-Place Firm Transportation firm transportation to cover growth plans Massive Reserve Base 4.9 Tcfe 2P / 2.7 Tcfe 1P reserves (6.9 Tcfe / 3.4 Tcfe Pro Forma) Sales Market Diversity less than 9% of 2017 revenue from Station 2 spot Deep Drilling Inventory management estimates 2,000+ drilling locations (3,000 Pro Forma) Liquids-Rich up to 60 bbls/MMcf at Townsend, Beg and Jedney

27

Appendices and Advisories

7.5x 2016 2P Production Replacement (1)

102% Increase in PDP Reserves from December 31, 2015 (1)

2016 Reserve Highlights (Stand Alone) Deep Value

At December 31, 2016(1):

2P Reserves

Increase in 2P Reserves from December 31, 2015 (1)

1P Reserves

Increase in 1P Reserves from December 31, 2015 (1)

4.9 Tcfe 7% 2.7Tcfe

31% 5.8x 2016 PDP Production Replacement (1)

(1) See “Advisories” section. (2) Based on fourth quarter 2016 annualized production (3) NAV calculated using the NPV10 of 1P reserves as prepared by GLJ Petroleum Consultants effective December 31, 2016, plus undeveloped land evaluated by Seaton-Jordan & Associates Ltd., less bank debt

and working capital deficiency (excluding mark-to-market unrealized hedging gains / losses), NAV Per Share calculated using fully diluted shares outstanding as of December 31, 2016. (4) FDC – Future Development Capital is capital necessary to develop those reserves deemed Undeveloped

$3.8 billion NPV10 2P Reserves (1)

$2.3 billion NPV10 1P Reserves (1)

$0.7 billion NPV10 PDP Reserves (1)

$2.3 billion 1P Net Asset Value (NAV) (3)

$22.91 1P NAV per Share (3)

$0.7 billion PDP Net Asset Value (NAV) (3)

$7.04 PDP NAV per Share (3)

1P FD&A per Mcfe (including change in FDC)(4)

PDP FD&A per Mcfe (including change in FDC)(4)

2P Reserve Life Index(2) 1P Reserve Life Index(2)

28

13.4x 2016 1P Production Replacement (1)

PDP Reserves 484 Bcfe

33 years

2.6times 1P Recycle Ratio (FD&A)

PDP Recycle Ratio (FD&A)

$0.72 $0.56

61 years

2.0times

Proposed West Coast LNG Projects

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—1.3 Bcf/d

~18.5 Bcf/d

Proposed LNG Projects Capacity Exxon – Imperial WCC LNG

—4.0 Bcf/d

—3.2 Bcf/d

—0.3 Bcf/d Pacific Oil & Gas Woodfibre LNG

—3.1 Bcf/d

—2.6 Bcf/d

—2.6 Bcf/d

—1.4 Bcf/d

Petronas – Japex Pacific Northwest LNG

Veresen Inc Jordan Cove LNG

Chevron – Apache KM LNG

Total Filed Application Capacity (NEB)

Shell – Petrochina, Mitsubishi, KOGAS LNG Canada

Nexen / CNOOC – Inpex, JGC Aurora Liquefied Natural Gas Ltd.

Kitsault Energy Ltd. Kitsault Energy Ltd. (Private)

Equity Research Sell-Side Analyst Coverage

Institution Analyst AltaCorp Capital Patrick O’Rourke

BMO Capital Markets Joe Levesque

Canaccord Genuity Corp. Anthony Petrucci

CIBC World Markets David Popowich

Cormark Securities Inc. Garett Ursu

Credit Suisse Securities David Phung

Desjardins Capital Markets Jamie Kubik

GMP FirstEnergy Cody Kwong

IA Securities 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

30

Corporate Overview

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

Transfer Agent TSX Trust Company

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: info@paintedpony.ca www.paintedpony.ca

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Advisory

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 year ended December 31, 2016, 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 Corporation’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 Corporation set forth in this presentation, including statements regarding management’s assessment of the Corporation’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 Corporation’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 Corporation’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 Corporation will derive therefrom. All subsequent forward-looking statements, whether written or oral, attributable to the Corporation 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 Corporation’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 Corporation’s website (www.paintedpony.ca), including the Corporation’s MD&A for the quarter and year ended Dec 31, 2016.

The forward-looking statements contained in this presentation are made as of the date on the front page and the Corporation 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 Corporation believes that such information is accurate and that the sources from which it has been obtained are reliable. The Corporation cannot guarantee the accuracy of such information, however, and has not independently verified the assumptions on which such information is based. The Corporation 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 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 presentation was made as of the date of this presentation and was provided for the purpose of providing information about management's current expectations and plans relating to the future, including with respect to the Corporation’s ability to fund its expenditures. The Corporation disclaims any intention or obligation 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 are cautioned 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 are expressly qualified by this cautionary statement.

NON-GAAP MEASURES This 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 investors with additional information regarding the Corporation’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 and financing activities or net earnings as determined in accordance with IFRS, as an indicator of the Corporation’s performance or liquidity. Cash flow is used by the Corporation to evaluate operating results and the Corporation’s ability to fund capital expenditures and repay debt. The Corporation uses net debt as a measure to assess its financial position. Net debt includes current liabilities, including the Corporation’s credit facility, less current assets excluding risk management contracts.

Included in this presentation are estimates of the Corporation's 2017-2018 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 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 Corporation in March 2017 and are included to provide readers with an understanding of the Corporation'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.

32

Advisory

NOTE REGARDING RESERVES DISCLOSURE The securities regulatory authorities in Canada have adopted National Instrument 51-101 – Standards of Disclosure for Oil and Gas Activities (“NI 51-101”), which imposes oil and gas disclosure standards for Canadian public issuers engaged in oil and gas activities. NI 51-101 permits oil and gas issuers, in their filings with Canadian securities regulatory authorities, to disclose proved, probable and possible reserves, and to disclose reserves and production on a gross basis before deducting royalties. Probable and possible reserves are progressively less certain estimates than proved reserves.

All reserves information in this presentation are presented on a gross basis. Gross reserves are the total working interest reserves before the deduction of any royalties and including any royalty interests receivable. Reserves estimates set forth herein with respect to the Corporation are based on the independent engineering evaluation of the Corporation’s oil, natural gas liquids and natural gas reserves (the “GLJ Report”) prepared by GLJ Petroleum Consultants Ltd. (“GLJ”) effective December 31, 2016 and dated February 27, 2017, and reserves estimates set forth herein with respect to the Target are based on an independent engineering evaluation of the Target’s oil, natural gas liquids and natural gas reserves (the “McDaniel Report”) prepared by McDaniel & Associates Consultants Ltd. (“McDaniel”) effective December 31, 2016 and dated February 6, 2017. Before tax net present values set forth herein are based on a 10 percent discount rate and GLJ’s January 1, 2017 forecast prices or McDaniel’s January 1, 2017 forecast prices, as applicable.

All estimates of future revenue in this presentation and in the documents incorporated herein by reference are, unless otherwise noted, after the deduction of royalties, development costs, production costs and well abandonment costs but before deduction of future income tax expenses and before consideration of indirect costs such as administrative, overhead and other miscellaneous expenses. The estimated future net revenues contained in this presentation and in the documents incorporated herein by reference do not represent the fair market value of the applicable reserves.

In this presentation: (a) the discounted and undiscounted net present value of future net revenues attributable to reserves do not represent the fair market value of reserves; (b) there is no assurance that the forecast prices and costs assumptions will be attained and variances could be material. The recovery and reserve estimates of natural gas and liquids reserves provided in this presentation are estimates only and there is no guarantee that the estimated reserves will be recovered. Actual natural gas and liquids reserves may be greater than or less than the estimates provided in this presentation; (c) 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; (d) boe amounts may be misleading, particularly if used in isolation. Boe amounts have been calculated using the conversion ratio of six thousand cubic feet (6 Mcf) to one barrel of oil (1 bbl). A conversion ratio of 6 Mcf to 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 that the value ratio based on the current price of crude oil as compared to natural gas is significantly different from the energy equivalency of 6:1, utilizing a conversion on a 6:1 basis may be misleading as an indication of value; and (e) Mcfe amounts may be misleading, particularly if used in isolation. Mcfe amounts have been calculated by using the conversion ratio of 1 bbl to 6 Mcf. A conversion ratio of 1 bbl to 6 Mcfs based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead. Given that the value ratio based on the current price of crude oil as compared to natural gas is significantly different from the energy equivalency of 1:6, utilizing a conversion on a 1:6 basis may be misleading as an indication of value.

Reserves are the estimated remaining quantities of conventional natural gas, shale gas and natural gas liquids anticipated to be recoverable from known accumulations, from a given date forward, based on: (i) analysis of drilling, geological, geophysical and engineering data; (ii) the use of established technology; and (iii) specified economic conditions which are generally accepted as reasonable.

Reserves are classified according to the degree of certainty associated with the estimates. (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.

Other criteria that must also be met for the categorization of reserves are provided in the Canadian Oil and Gas Evaluation (“COGE”) Handbook.

Each of the reserves categories (proved and probable) may be divided into developed and undeveloped categories. (a) 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 (for example, when compared to the cost of drilling a well) to put the reserves on production. The developed category may be subdivided into producing and non-producing.

(i) Developed producing reserves are those reserves that are expected to be recovered from completion intervals open at the time of 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 certainly. (ii) 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. 33

Advisory

(b) Undeveloped reserves are those reserves expected to be recovered from known 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) to which they are assigned.

In multi-well pools it may be appropriate to allocate total pool reserves between the developed and undeveloped categories or to subdivide the developed reserves for the pool between developed producing and developed non-producing. This allocation should be based on the estimator’s assessment as to the reserves that will be recovered from specific wells, facilities and completion intervals in the pool and their respective development and production status.

The qualitative certainty levels referred to in the definitions above are applicable to individual reserves entities (which refers to the lowest level at which reserves calculations are performed) and to reported reserves (which refers to the highest level sum of individual entity estimates for which reserve estimates are prepared). Reported reserves should target the following levels of certainty under a specific set of economic conditions:

(a) at least a 90 percent probability that the quantities actually recovered will equal or exceed the estimated proved reserves; and (b) at least a 50 percent probability that the quantities actually recovered will equal or exceed the sum of the estimated proved plus probable reserves.

A quantitative measure of the certainty levels pertaining to estimates prepared for the various reserves categories is desirable to provide a clearer understanding of the associated risks and uncertainties. However, the majority of reserves estimates will be prepared using deterministic methods that do not provide a mathematically derived quantitative measure of probability. In principle, there should be no difference between estimates prepared using probabilistic or deterministic methods.

Additional clarification of certainty levels associated with reserves estimates and the effect of aggregation is provided in the COGE Handbook.

For additional information regarding the presentation of the Corporation’s reserves and other oil and gas information, see the Corporation’s Form 51-101F1, which may be accessed through the SEDAR website (www.sedar.com) or the Corporation’s website (www.paintedpony.ca).

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