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Investor Update October 1, 2018

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Page 1: Investor Update - s2.q4cdn.coms2.q4cdn.com/.../doc_presentations/2018/10/01_10_2018_Investor-U… · Corporate Profile TSX: PONY Our Growth 38% forecasted annual average daily production

Investor Update

October 1, 2018

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Why we do what we do…

We believe:

• world demand for clean and reliable source of energy is rapidly growing

• technological advancements makes our energy cost competitive on a world scale

• in developing our world-class resource using the highest standards, environmentally and socially

• The world trusts doing business with Canada

PONY is developing a world-class resource of clean natural gas in Canada

Source: BP Global Energy Outlook, 2017

*Renewables includes wind, solar, geothermal, biomass, and biofuels

Billion Toe (tonnes of oil equivalent)

2

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Increases in Canadian natural gas demand is expected to be significant

Estimated 50% potential growth in demand for Canadian natural gas in the next 5 years.

Canadian Natural Gas MarketFuture Growth

Source: RBC Capital Markets; January 2018

50%

0.0

1.0

2.0

3.0

4.0

5.0

6.0

2017 2018 2019 2020 2021 2022 2023 2024 2025 2026

PotentialCanadian LNG

Projects

Coal to Gas Switching

Oil Sands Demand Growth

NGTL

Alliance

T-South

~2 Bcf/d of high confidence demand growth in the next 5 years; potential for 8+ Bcf/d of growth if LNG potential is realized

Gas

Dem

and

Gro

wth

(B

cf/d

)

3

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Proposed LNG Projects Capacity

Exxon – ImperialWCC LNG ~4.0 Bcf/d

Shell & Partners - LNG Canada(FID expected in 2018) ~1.9 – 3.8 Bcf/d

Pembina Pipeline Corp.Jordan Cove LNG ~1.4 Bcf/d

Chevron / WoodsideKM LNG ~1.3 Bcf/d

Pacific Oil & Gas / Woodfibre LNG(FID expected in 2018) ~0.3 – 1.0 Bcf/d

TOTAL ~8.9 – 11.5 Bcf/d

AltaGas Ridley

Island Propane

Export Terminal

T-North Enbridge

Mainline

Proposed Canada

LNG (Shell)

Export Facility

T-South Enbridge

Mainline

36” and 38”

Proposed

Woodfibre LNG

Export Facility

AltaGas Propane

Export Terminal

Ferndale, WA

4

Proposed West Coast LNG ProjectsGame Changer

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Transportation Firm Transportation & Toll Advantage to West Coast

(increases to 90 MMcf/d Nov 2019)

Enbridge T-North Tolls

• Single toll structure

• $0.18/Mcf

• Pony can deliver at either Station 2 or Sunset Creek for single toll

TransCanada AECO Tolls

• $0.27/Mcf receipt on AECO at Sunset Creek

• $0.20/Mcf delivery off AECO

• $0.81/Mcf delivery into Dawn

5

PONY has a toll advantage to the west coast over natural gas coming from Alberta

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Corporate ProfileTSX: PONY

OurGrowth

38% forecasted annual average daily production volume growth (2018 vs. 2017)

46% forecasted annual average daily liquids production growth (2018 vs. 2017)

28% forecasted cash flow per share growth (2018 vs. 2017)

Trading Metrics

1.1 mm shares trade per day

$500 mm market capitalization

161 mm shares outstanding

Balance Sheet

$142 mm term debt maturing 2022; $45 mm convertible debentures maturing 2021

$372 mm total debt as at June 30, 2018

Production361 MMcfe/d (60,116 boe/d) Q2 2018, up 48% over Q2 2017

5,514 bbls/day Q2 2018 liquids production, up 98% over Q2 2017

348 MMcfe/d (58,000 boe/d) to 360 MMcfe/d (60,000 boe/d) 2018 Production Guidance

$184 mm bank debt on borrowing base of $400 million as at June 30, 2018

28% Corporate Production Decline at December 31, 2017 per GLJ Petroleum Consultants

6

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World Class ResourceMontney Pure Play

(1) As at December 31, 2017; see Advisories Section(2) RLI (Reserve Life Index) is calculated using 2017 reserves divided by annualized Q1 2018 production volumes of 364 MMcfe/d (60,703 boe/d)

Asset• The Montney is the most economic natural gas liquids play

in Canada

• 306 net sections (195,840 net acres) of Montney lands

• 6.9 Tcfe (1,148 MMboe) Proved Plus Probable Reserves(1)

with a Proved Plus Probable RLI(2) of 52 years

• 797 Bcfe of Proved Developed Producing reserves

Strategic Advantages• Firm transportation and processing facilities in-place to

meet production growth targets

Sustainable Capital Investment• Cash flow 2018 capital budget provides production volume

and cash flow per share growth without additional leverage

7

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Montney Pure PlayLocation, Location, Location

LEGEND

Painted Pony Lands

Painted Pony / AltaGas Facilities

Third-Party Facilities

Enbridge T-North Pipeline

Secondary Pipelines

PONY’s Montney Sweet Spot is:

• 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 an area with up to 1.8x over-pressured reservoir

• liquids cut average of approximately 9% during first quarter 2018

• high liquids production at Townsend with potential at Beg and Jedney (drilled and tested first well at Beg in Q1 2018)

• liquids production over a total of approximately 100,000 acres or 50% of land base

Townsend

Kobes

Blair

Daiber

Beg

West Blair

Cypress

LEGEND

Painted Pony Lands

Painted Pony / AltaGas Facilities

Third-Party Facilities

Enbridge T-North Pipeline

Secondary Pipelines

Dry Liquids

38 sections

36 sections

40 sections

Blair 45 sections

Drilled first well at liquids-rich Beg during Q1 2018

8

South Townsend

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South Townsend WellsSignificant Liquid Yields

9

d-F57-H/94-B-9 WellFinal 24 hours of the seven day test period: • 3,000 boe/d (38% liquids)

• 11.1 MMcf/d of natural gas • 1,140 bbls/d of natural gas liquids (83% condensate) • flowing pressure of 2,280 psi through a 9/16 inch choke

d-E57-H/94-B-9 WellFinal 24 hours of the 14 day test period:• 2,300 boe/d (38% liquids)

• 9 MMcf/d of natural gas • 865 bbls/d of natural gas liquids (82% condensate)• flowing pressure of 1,900 psi through a 9/16 inch choke.

SouthTownsend

PONY 57-H Pad

Townsend

• Two Lower Montney horizontal test wells from a single pad

• Open-hole ball drop completion system

• 1.8x over-pressured

• Pipeline connected to the AltaGas Townsend Facility

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Beg Test WellSignificant Untapped Value in Liquids-Rich Block

• Final 8 hours of seven day test

• 2,000 boe/d consisting of:

• 10 MMcf/d natural gas

• 360 bbls/d liquids including wellhead and facility recovered liquids; 60% condensate

• Well was still cleaning up

• Flowing pressure at end of test was 1,625 psi through a 5/8 inch choke

• Will require a 12 kilometer (7.5 mile) pipeline to existing infrastructure

3 km

Beg

Blair

Jedney

Black Swan - Beg 20-H2 Upper Montney wells5.5 MMcf/d7 bbls/MMcf Free Condensate

PONY Beg 65-BUpper Montney well10 MMcf/d360 bbls/d liquids / 36 bbls/MMcf(60% Condensate)

Black Swan - Beg 80-G3 Upper Montney wells6 - 8.5 MMcf/d5 - 17.5 bbls/MMcf Free Condensate

Progress - Beg 27-B3 Upper Montney wells9.5 - 11 MMcf/d10 - 16.5 bbls/mmcf Free Condensate

Progress - Beg 84-J3 Upper Montney wells9 - 11 MMcf/d11 - 32 bbls/MMcf Free Condensate

Black Swan - Beg 97-IUpper Montney well8 MMcf/d20 bbls/MMcf Free Condensate

10

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-

250,000

500,000

750,000

1,000,000

1,250,000

1,500,000

1,750,000

2,000,000

2,250,000

Painted PonyOther Producers

Source: GeoScout; As at Jan 31, 2018

Based on cumulative

volumes, PONY

has 19 of the top

20 wells in the

Northern Montney

47 of top 100 wells are PONY

wells!

Top 100 Wells - Northern Montney Field (sample set of 1,220 wells)

North Montney 6-Month Cumulative Production Volumes

Cu

mu

lati

ve N

atu

ral G

as (

Mcf

)The Sweet SpotTop Decile Well Performance

PONY has best well in North Montney with 6-month

average daily production rate of more than 11 MMcf/d

11

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0

10

20

30

40

50

60

70

80Ja

n-1

5Fe

b-1

5M

ar-1

5A

pr-

15

May

-15

Jun

-15

Jul-

15

Au

g-1

5Se

p-1

5O

ct-1

5N

ov-

15

Dec

-15

Jan

-16

Feb

-16

Mar

-16

Ap

r-1

6M

ay-1

6Ju

n-1

6Ju

l-1

6A

ug-

16

Sep

-16

Oct

-16

No

v-1

6D

ec-1

6Ja

n-1

7Fe

b-1

7M

ar-1

7A

pr-

17

May

-17

Jun

-17

Jul-

17

Au

g-1

7Se

p-1

7O

ct-1

7N

ov-

17

Dec

-17

Jan

-18

Feb

-18

Mar

-18

Ap

r-1

8M

ay-1

8Ju

n-1

8Ju

l-1

8A

ug-

18

Sep

-18

Oct

-18

No

v-1

8D

ec-1

8

Pro

du

ctio

n V

olu

mes

(m

bo

e/d

)

Production ProfileImpressive Growth

2017

2016

2015 (base)

2018f

94 MMcfe/d(15,604 boe/d)

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

257 MMcfe/d(42,882 boe/d)

348-360 MMcfe/d(58,000-60,000 boe/d)

PONY is expecting 38% annual average daily production growth from 2017 to 2018

Excluding 2018 Capital Program Volumes, PONY’s production YE 2018

would be approximately 258 MMcfe/d or (43,000 boe/d),

representing a 28% corporate decline

Year End 2017 360 MMcfe/d

(60,000 boe/d)

Per GLJ Reserve Report Dec 31, 2017

28% Corporate Decline

12

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$0

$2,000,000

$4,000,000

$6,000,000

$8,000,000

$10,000,000

$12,000,000

$14,000,000

Dri

ll an

d C

om

ple

tio

n C

ost

($

)

Perf & Plug Systems21 wells

D&C cost $7.7 million

2011 2012 2013 2014 2015 2016 2017

1st Generation Open Hole Ball Drop System

33 wellsD&C cost $6.9 million

Current Generation Open Hole Ball Drop System

111 wellsD&C cost $4.2 million

As capital well costs fell, production type curves dramatically improved

Management Type Curve

increased 50%

PONY Well Cost (Drill + Complete Cost)

Historical CostsDrilling & Completions Efficiency

Continued type curve improvement with average well booking of 9 Bcfe/well

13

2018

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-

1,000

2,000

3,000

4,000

5,000

6,000

7,000

8,000

Single Well Economics IRR NPV10

Daiber (dry)

54% $4.7 mm

Blair (lean; 15 bbls/MMcf)

64% $6.2 mm

Townsend (liquids-rich; 36 bbls/MMcf)

39% $2.9 mm

Capital Costs

Drilling $1.9 million

Completions $2.1 million

Equip / Tie-in $0.55 million

TOTAL $4.55 million

9 months 18 months0 months

Townsend (liquids-rich)

Daiber (dry)

Blair (lean)

Management Type Curves

Single Well Economics by Area2018 Management Type Curves

Cal

end

ar D

ay G

as E

qu

ival

ent

(Mcf

e/d

)

Based on: $65/bbl WTI; $2.00/Mcf AECO; USD/CAD $0.79

3 months 6 months 12 months 15 months

14

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0%

20%

40%

60%

80%

100%

120%

$1.75 $2.00 $2.25 $2.50

Rat

e o

f R

etu

rn (

% B

T)

AECO

Townsend (liquids-rich) Blair (lean) Daiber (dry)

Pricing Flat at: $65/bbl WTI; USD/CAD $0.79

Single Well Development Economics Price Sensitivity (Half Cycle)

High-rate Daiber wells provide natural

gas pricing torque

Liquids-enhanced, Blair wells provide exposure to stronger Condensate, NGL

and natural gas pricing

15

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0

2

4

6

8

10

12

TOU CNQ PONY ECA BIR VII ARX PEY CVE AAV POU BNP CR NVA BXE KEL SRX PMT PNE PRQ LXE

Total Proved Probable

6.5

9.5

6.2

5.0 4.9

3.8 3.83.3

2.3 2.21.9

1.71.4

1.0 0.8 0.60.4 0.3 0.2 0.2

Nat

ura

l Gas

Res

erve

s (T

cf)

Canadian Natural Gas ReservesAs at Dec 31, 2017

10.7

PONY’s Proved plus Probable natural gas reserves of 6.5 Tcf (excludes liquids) positions PONY with the third-largest natural gas reserves of any publicly traded company in Canada

Assuming Enterprise Value@ $5.16/sh

($2.85/sh equity + $2.31/sh debt) on 6.9 Tcfe of 2P Reserves

$5.16/sh

42.9 Mcfe/shor

7.14 boe/sh

=$0.12/Mcfe

or

$0.72/boe

73 MMbbls of Proved plus Probable liquids

$5.16/sh (EV)

0.45 bbls/sh= $11.47/2P bbl

16

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PDP0.8 Tcfe

Proved Undeveloped

2.3 Tcfe

Probable3.8 Tcfe • 64% increase in Proved Developed Producing reserves

• 26% of Total Proved reserves are Proved Developed Producing

• 41% increase in Proved Plus Probable reserves

• 45% of Proved Plus Probable reserves are Total Proved

• Proved Plus Probable reserves include 73 MMbbls of liquids

• Reserve Life Index of:

• 7 years - Proved Developed Producing

• 27 years - Total Proved

• 52 years - Proved Plus Probable

NPV10 $905 MM

NPV10 $1.7 billion NPV10

$740 MM

*Note: NPV calculated using 10% discount rate; GLJ Pricing as of January 2018; 2018 AECO $2.20/MMbtu; 2019 AECO $2.54/MMbtu

Proved Plus ProbableTotal Proved

Reserve Information As at Dec 31, 2017

2017 Reserves Highlights

6.9 Tcfe of Proved Plus Probable reserves with an NPV10 of $3.3 billion* ($20.53/share)

Tcfe

0.0

1.0

2.0

3.0

4.0

5.0

6.0

7.0

8.0

2011 2012 2013 2014 2015 2016 2017

0.8 1.11.7

2.9

4.64.9

6.9

Probable Proved Undeveloped Proved Developed Producing

PONY Reserve Growth

17

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2017 FD&A Recycle Ratios (incl FDC changes) 3-Year Average FD&A Recycle Ratios (incl FDC changes) 2017 F&D Recycle Ratio

1.0x

2.0x

3.0x

0.0x

1.1x1.3x

1.6x1.8x

1.9x

3.2x

20

17

Rec

ycle

Rat

ios

4.0x

1.6x

Note: FD&A – Finding, Development & Acquisition costsF&D – Finding and Development costs

Recycle RatiosLow-Cost 3-Year Average Reserve Additions

1.6x Proved Developed Producing 2017 F&D Recycle Ratio

18

Proved Developed Producing Total Proved Proved plus Probable

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Land ValuationRecent Land Sales Suggest PONY Undervalued

• Recent land sales have shown significant value in north east BC acreage

• PONY has five largely contiguous land blocks totaling 201,090 net acres (314 net sections) of Montney rights in north east BC

• The weighted-average price per acre over the past two years for Montney parcels which are proximate to PONY is $4,703/acre

• PONY’s 201,090 net acres carry an implied value, using the recent weighted-average per acre value, of approximately $945 million

Bernadet (Conoco) $4,454/acre (34,580 acres)$154 million / April 2018

West Inga$3,984/acre (1,305 acres) $5.2 million / Sept 2017

Bernadet $9,095/acre (4,618 acres)

$42 million / June 2018

Altares$5,623/acre (13,695 acres)

$77 million / July 2017

Inga$3,117/acre (1,305 acres)$4,067 million / July 2017

Bernadet$3,928/acre (23,422 acres)$92 million / March 2017

• Recent land sales have shown significant value in north east BC acreage

• PONY owns five largely contiguous land blocks totaling 195,840 net acres (306 net sections) of Montney rights in north east BC

• The weighted-average price per acre of land transactions for the past two years for Montney parcels which are proximate to PONY is $4,703/acre

• PONY’s 195,840 net acres carry an implied value, using recent weighted-average per acre values, of approximately $920 million

PONY

Progress

ConocoPhillips

Saguaro

Kelt

Canbriam

Black Swan

Storm

Tourmaline

CNRL

Todd

19

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$29 $107 $56 $204 $108 $303 $1550

100

200

300

400

500

$0

$50

$100

$150

$200

$250

$300

$350

$400

$145

2018 Sustainable Capital SpendingCash Flow Budget

2015 2017

5.7x 2.6x 2.7x

2018e2016

2.0xYear-End Net

Debt to Q4 Annualized Cash Flow

$0.56/share $0.76/share $0.97/share

$0.29/share

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

257 MMcfe/d(42,882 boe/d)

348 – 360 MMcfe/d(58,000 – 60,000 boe/d)

94 MMcfe/d(15,604 boe/d)

At $2.00 AECO, PONY grows year-over-year cash flow per share by 28% in 2018

36% CFPS

Growth

80% CFPS

Growth

Annual Average Daily Production (forecast)

Annual Average Daily Production (actual)

Capital Development Program

Cash Flow (actuals)

2018 Cash Flow (forecast)

Net of Interest Expense, G&A, and Capital Lease Expense

(2018 pricing based on WTI US$65/bbl, NYMEX USD$3.00, AECO CAD$2.00/Mcf, F/X CAD$0.79)

28% CFPS

Growth

$165

2018 capital development program to be $145 - $165 million, matching 2018 cash flow

20

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$0.00

$0.20

$0.40

$0.60

$0.80

$1.00

$1.20

$1.40

$1.60

$1.75 $2.00 $2.25 $2.50 $2.75 $3.00 $3.25 $3.50 $3.75 $4.00

Cas

h F

low

($

/mcf

e)

AECO Price $/mcf

2018 Corporate Cash Flow SensitivityCash Flow Capital Budget

USD$65/bblFX CAD $0.79

Cash Flow (including hedges)Cash Flow (excluding hedges)

Physical and financial fixed price hedges provide significant protection from natural gas price volatility, stabilizing annual cash flow

21

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$0.00

$0.50

$1.00

$1.50

$2.00

$2.50

$3.00

$3.50

$0.00

$0.50

$1.00

$1.50

2018f

Pre-Tax Earnings

$0.25

Non-cash Items* ($0.96)

*Non-cash items include stock based compensation, accretion expense, and DD&A (does not include unrealized gain/loss on risk management contracts)

$3.35/Mcfe

Top Line Revenue (including Hedging)

($0.14)

($0.20)

($0.42)

Hedging Gain $0.23

2018f2018 pricing at:

$65/bbl WTI; $2.00/Mcf AECO; USD/CAD $0.79

Solid Margins Drive EarningsCost Efficiencies Drive Higher Cash Flow per Mcfe

Royalties ($0.06)

Operating Cost ($0.59)

Transportation ($0.72)

G&A ($0.14)

Interest ($0.19)

Capital Lease ($0.44)

Cash Flow $0.98 (before hedging)

PONY can deliver earnings despite low AECO prices due to very low DD&A driven by strong capital efficiencies

Diverse fixed-price contracts and financial hedges deliver strong netbacks despite low

AECO pricing

$1.21/Mcfe

Cash Flow

22

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Return on Average Capital Employed (ROACE) Illustrates Operational Sustainability

Source: Scotiabank Global Banking and Markets – “The Valuation Book” February 2018; ROACE = earnings before interest & taxes (EBIT) / (average total assets – average current liabilities)

11%

-25%

-20%

-15%

-10%

-5%

0%

5%

10%

15%

20%

25%

-25%

-20%

-15%

-10%

-5%

0%

5%

10%

15%

20%

25%

-25%

-20%

-15%

-10%

-5%

0%

5%

10%

15%

20%

25%

XEC

NFX

VN

OM LP

I

CH

K

SRC

I

JAG

FAN

G

CR

ZO

EOG

GP

OR

CO

G

DV

N

SWN

CP

E

AR

MTD

R

CX

O

WR

D

RSP

P PE

CLR

PXD

OXY

AP

A

CD

EV

EQT

RR

C

EGN HK

EPE

NB

L

ECR

PD

CE

MU

R

BB

G

MR

O

QEP SM WLL

WP

X

AP

C

KO

S

HES

Average US

4.3%Average Canada

4.2%

2017 Canadian ROACE2017 US ROACE

North American Producers 2017 ROACE

-98%

-98

%

PONY’s returns rank amongst the highest by North America E&Ps

11%

23

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Market DiversificationNatural Gas Sales Points

Chicago

LNG Export

Dawn

NYMEXMexico Export

PONY Sales / Pricing Exposure

Medicine Hat

AECO

1 GMP FirstEnergy Forecast – January 2018

Current US Exports 3.8 Bcf/d2019 Additions 2.7 Bcf/d 2020 Additions 3.0 Bcf/d1Total (end 2020) 9.5 Bcf/d

AECO Markets152 161 MMcf/d end of 2018 (fixed price & spot)

MEDICINE HAT14-year contract to initially deliver 10 MMcf/d to Methanex’s methanol plant in Medicine Hat, Alberta increasing to 50 MMcf/d by 2023

Map here

Current 4.5 Bcf/d1End 2019 5.2 Bcf/d

Malin

DAWN Market33 MMcf/d (Current) 44 MMcf/d (Nov 2018)88 MMcf/d (Nov 2019) (fixed price & spot)

SUMAS Market28 32MMcf/dEnd of 2018(spot)

NYMEX Market40 26 MMcf/d end of 2018 (basis contracts)

Station 2

Sumas

24

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Fixed Price Contract Pricing

Exposures

Station 2

$2.80/Mcf21%

AECO$3.04/Mcf

31%

Liquids

$67.68/bbl38%

DAWN

$3.98/Mcf10%

Expected 2H 2018 Production

Revenue by Source

NGL & Condensate

5%

Volumes not under contract are presumed to be sold at index pricing as at Aug 1, 2018

2018 Production RevenueManaging Volatility

63% of PONY’s Q3/Q4 2018 production revenue are protected

through a combination of physical and financial contracts at a volume-

weighted average price of $4.19/Mcfe (average of $3.00/Mcf for natural gas and $67.68/bbl for liquids)

Fixed Price Contracts

63%

DAWN 9%

SUMAS 6%

AECO 10%

NYMEX8%

25

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Percentage on Fixed Price Contract (Financial and Physical)

Hedging ProfilePrudent Risk Management

50%

44%47%

94%

98%96%

24% 24% 24%

0%

25%

50%

75%

100%

Q3 2018 Q4 2018 Average Remaining2018

Natural Gas Hedges Liquids Hedges Propane Hedges

Perc

enta

ge F

ore

cast

Pro

du

ctio

n H

edge

d

$3.02Mcf $3.01

Mcf

$72.69bbl

$72.70bbl

$72.70bbl

$38.82bbl

$38.82bbl

$38.82bbl

$3.00Mcf

Nat

ura

l Gas

Vo

lum

e H

edge

d (

Mcf

/d)

Fixed Price Contract Volumes(Financial / Physical Fixed Price)

$3.07Mcf

26

114

71

40

27

63

2,750 2,750 2,750 2,750 2,750

250 250 250 250 250

0

1,000

2,000

3,000

4,000

5,000

0

25

50

75

100

125

150

Q1 2019 Q2 2019 Q3 2019 Q4 2019 Average2019

Liqu

ids V

olu

me H

edged

(bb

ls/d)

Station 2 FP$2.7435%

Liquids FP$74.28/bbl

20%

DAWN FP$3.6713%

AECO FP $3.2330%

2019 FP Pricing

Propane FP $37.02/bbl

2%

Natural Gas Hedges Liquids Hedges Propane Hedges

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Massive reserves base

Top well performance with increasing liquids cut

Low well costs

Firm transportation to diverse pricing hubs

Attractive relative valuation

Well situated to supply Canadian west coast LNG projects

Pony PointsChecking Off All of the Boxes

27

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Appendices & Advisories

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Diversified Market Exposure2018 / 2019 Sales Contracts Support Strong Netbacks

Reflective of PONY’s heat content, natural gas volumes converted from GJ to Mcf at a conversion ratio of 1 : 1.15

28

Index pricing as of August 1, 2018; All currency CAD$

Painted Pony actively markets the majority of natural gas volumes into a diversity of sales points and accessing a diversity of pricing

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Financial Strength Term Debt and Credit Facility Provide Flexibility

$400 Million Syndicated Credit Facility• Secured, Reserve Based Lending• Matures May 2020• $184 million drawn as at June 30, 2018• $41 million in Letters of Credit

$142 Million Term Debt (Senior Unsecured Notes)• Held by Magnetar Capital• 8.5% Coupon • Mature in 2022• Not callable for 3 years

$45 Million Subordinated Convertible Debentures• Held by Magnetar Capital• 6.5% Coupon • $5.60 Conversion Price• Mature in 2021 (subject to any conversion)• ‘No Shorting’ Provision included

Debt Capital Diversification

Syndicated Credit Facility

Drawn on Credit Facility

Undrawn

Letters of Credit

Drawn on Credit Facility

Senior Notes

Convertible Debentures

$175 $184

$41

$184

$142

$45

29

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Institution Analyst

AltaCorp Capital Patrick O’Rourke

BMO Capital Markets Michael Murphy / Ray Kwan

Canaccord Genuity Corp. Anthony Petrucci

CIBC World Markets David Popowich

Cormark Securities Inc. Garett Ursu

Eight Capital Adam Gill

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

Tudor Picker Holt & Co Aaron Swanson

Equity ResearchSell-Side Analyst Coverage

30

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Auditor KPMG LLP

Evaluation Engineers GLJ Petroleum Consultants Ltd.

Banks

Transfer Agent

The Toronto-Dominion Bank

The Bank of Nova Scotia

Alberta Treasury Branches

Canadian Imperial Bank of Commerce

Royal Bank of Canada

HSBC Bank Canada

Wells Fargo Bank

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: [email protected]

www.paintedpony.ca

Corporate Overview

31

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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 June30, 2018, 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 capitalexpenditures; (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 thatassumptions 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 certainprospects, 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 andcosts 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 underapplicable 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 theCorporation’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, theimpact 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 drillingrigs 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 obtainrequired 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 andregulations (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 ofcompanies with respect to announced transactions and the final valuations thereof. Aboriginal peoples have claimed aboriginal title and rights to portions of western Canada, including northeast British Columbia. On March 3, 2015, theBlueberry River First Nation (BRFN) filed a claim against the Province of British Columbia, which sought relief for alleged breaches of treaty rights in northeast British Columbia. The underlying claim was originally scheduled to be heardby the British Columbia Supreme Court commencing in July 2018, but has now been adjourned until October 15, 2018, with a possible further adjournment date of April 29, 2019. The Corporation was not a party to the interlocutoryinjunction and it is not party to the underlying claim. In addition, beginning July 16, 2018, the British Columbia Oil & Gas Commission (OGC) is implementing interim measures into its application review process to address BRFNconcerns with respect to petroleum & natural gas development in certain defined areas within the BRFN traditional territory. Certain Painted Pony tenures lie within these defined areas where new surface disturbance will be restrictedand may be subject to additional review by the OGC. 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 expressedin, 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 theCorporation 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 cautionarystatements. 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 accessedthrough the SEDAR website (www.sedar.com) or the Corporation’s website (www.paintedpony.ca), including the Corporation’s MD&A for the quarter June 30, 2018.

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 notindependently 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, netdebt 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 thispresentation 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. TheCorporation 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 pursuantto 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 statementsand 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 FinancialReporting 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 toprovide 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 moremeaningful than cash flows from operating activities as determined in accordance with IFRS as an indicator of the Corporation’s performance. Cash flow denotes cash flow from operating activities before the effects of changes in non-cash working capital, and decommissioning expenditures. 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 ameasure to assess its financial position. Net debt is a non-GAAP measure calculated as bank debt, senior notes, liability portion of convertible debentures, and working capital deficiency, adjusted for the net current portion of fair valueof risk management contracts and current portion of finance lease obligation. Included in this presentation are estimates of the Corporation's 2018 cash flow which are based on various assumptions as to production levels, commodityprices 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 estimatesconstitute a financial outlook, they were approved by management of the Corporation in May 2018 and are included to provide readers with an understanding of the Corporation's anticipated cash flow based on the capital expendituresand other assumptions described and readers are cautioned that the information may not be appropriate for other purposes.

Advisory

31

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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 issuersengaged 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 agross 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. Reservesestimates 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 PetroleumConsultants Ltd. (“GLJ”) effective December 31, 2017 and dated March 6, 2018, and reserves estimates set forth herein with respect to the Target are based on an independent engineering evaluation of the Target’s oil, natural gasliquids and natural gas reserves (the “McDaniel Report”) prepared by McDaniel & Associates Consultants Ltd. (“McDaniel”) effective December 31, 2017 and dated March 6, 2018. Before tax net present values set forth herein arebased on a 10 percent discount rate and GLJ’s January 1, 2018 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 abandonmentcosts 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 thispresentation 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 crudeoil 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 equivalencyconversion 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 issignificantly 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 theestimated 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 tothe 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 musthave 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.

32

Advisory

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(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 renderthem 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 andproduction 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 (whichrefers 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 ofreserves 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 usingprobabilistic 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).

33

Advisory