Investor Update

November 8, 2019

Why we do what we do…

We believe:

• world demand for clean and

reliable 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

Our Mission is to establish Painted Pony as a low-cost supplier

of clean natural gas to Canada and the world.

Source: BP Global Energy Outlook, 2018

*Renewables includes wind, solar, geothermal, biomass, and biofuels 1

Billion T

OE

(tonnes

of

oil e

quiv

ale

nt)

Oil

Coal

Perc

enta

ge o

f G

lobal Energ

y N

eeds

Gas

Source: US Energy Information Administration (EIA) June 4, 2019

2

229

161 157

139

117

0

50

100

150

200

250

Coal Diesel Gasoline Propane Natural Gas

Clean-Burning Natural GasLowest GHG Emissions

Pounds

of

CO

2Em

issi

ons

/ M

MBtu

Compared to clean

burning natural gas,

CO2 emissions from

coal are 96% higher

while diesel emissions

are 37% higher

PONY supplements diesel

fuel with natural gas fuel

completion operations

which reduces per well

capital costs and lowers

PONY’s GHG emissions

Converting coal-fired electricity

generations plants to natural

gas (including LNG) reduces

GHGs by 48%...a REAL solution

to lowering emissions

Global LNG MarketDemand Growth

1 - Source: BP statistical review, Kepler Cheuvreux estimates (Equity Research Q&A Report, April 23, 2019)

Glo

bal LN

G D

em

and

(Mtp

a)(1

)

181

221240 241 236 240 245

257

287

308323

340357

374393

413433

0

100

200

300

400

500

2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025

.

Global LNG demand could reach 433 Mtpa (57 Bcf/d) in 2025

Global LNG

demand increased

78%2009 - 2019

Global LNG

demand

forecasted to

increase

34%2019 – 2025(1)

Mtpa (Million Tonnes per Annum)

is a typical measurement unit in

LNG markets for production

Approximate conversion:

1 mtpa = 0.132 Bcf/d

1 Bcf/d = 7.576 mtpa

24

29

32 32 31 32 3234

38

4143

4547

49

52

55

57

Mtpa

Bcf/d

Bcf/d

Mtpa

3

4

Proposed West Coast LNG & LPG ProjectsGame Changer

AltaGas Ridley Island

Propane Export Terminal

40,000 bbl/d export

T-North Enbridge

Mainline

LNG Canada (Shell)

Export Facility

(Under Construction) T-South Enbridge

Mainline

36” and 30”Proposed

Woodfibre LNG

Export Facility

Petrogas Propane

Export Terminal

35,000 bbl/d export

Ferndale, WA

Coastal GasLink

LNG Projects Capacity

LNG Canada Shell, Petronas, Mitsubishi,

Petro-China, KOGAS (Under

Construction)

~1.9 – 3.8 Bcf/d

Woodfibre LNG(FID expected in 2019)

~0.3 – 1.0 Bcf/d

Kitimat LNGChevron / Woodside

~2.4 – 3.5 Bcf/d

Jordan Cove LNG (Washington state)

Pembina Pipeline Corp.

~1.0 – 1.6 Bcf/d

TOTAL ~5.6 – 9.9 Bcf/d

British Columbia

5

LNG Canada Construction UnderwayKitimat, BC Site

November 2019

August 2018

LNG Canada’s export

facility at Kitimat has

been under construction

since October 2018

2005 2010 2015 2020 2025 2030 2035 2040

0

5

10

15

20

25

Bcf/

d

Western Canadian

Conventional

BC Montney

AB Deep Basin

AB Montney

Western Canadian CBMWestern Canadian Solution Gas

Horn River

Shale

DuvernayRest of Canada

Conventional

Over the next 20 years, natural gas production from the Montney

in BC will continue to grow and by 2040 is estimated to make up

38% of Canada’s total natural gas production

Source: National Energy Board, Canada’s Energy Future, Energy Supply and Demand Projections to 2040, November 2018

6

NEBC Montney Massive Resource

2019

Alberta Natural Gas MarketContinued Demand Growth

7

0.0

2.0

4.0

6.0

8.0

2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023

Oilsands

Industrial / Petrochemical / Other

Alberta is expected to increase

natural gas consumption by over

45% between 2018 and 2023Electricity

Generation (including Coal-to-Gas Conversions)

2015

Natu

ral G

as

Dem

and (

Bcf/

d)

20150.0

2.0

4.0

6.0

8.0

• Significant demand growth is

taking place in Alberta

• Steady phase-out of coal in

electrical generation

• Increased demand for natural

gas in the oilsands

• Power demand continues to rise

• This does not include the impact

of west coast LNG exports

2015 2030

Electricity Generation Sources in Alberta

Source: GMP FirstEnergy, CAPP, AER

51% Coal

40% Natural Gas

9% Renewables

70% Natural Gas

30% Renewables

75% increase

in natural

gas demand

Corporate ProfileTSX: PONY

8Note: As at November 8, 2019

* RLI (Reserve Life Index) is calculated using 2018 2P reserves divided by Q4 2018 annualized production volumes of 315 MMcfe/d (52,453 boe/d)

2P Reserve Life Index* 60 Years

Enterprise Value $420 million

Common Shares Outstanding 161 million

First 9 Months of 2019 Average Daily Production 302 MMcfe/d (50,262 boe/d)

90-day Average Daily Volume 1.0 million shares per day

2019 Capital Budget $80 - $95 million

2P Reserves 6.9 Tcfe (1.15 billion boe)

PONY Ownership• Employees (65 full-time; via company savings plan) 1.9 million shares

• Officers (company savings plan and personal holdings) 2.7 million shares

• November PONY purchase (company savings plan) 210,000 shares

PONY Asset SaleSignificant Land Value

9

• Sold 11,280 gross acres (8,460 net acres) for cash proceeds of

$45 million

• Sale price of $5,300 per acre is consistent with average Montney

transactions over past two years

• Land sold was 4% of PONY acreage prior to closing for approximately 50% of

PONY’s market cap

• Cash proceeds reduced bank debt to $120 million on a $375 million bank

facility as of November 8, 2019

• No production or PDP reserves associated with the transaction

• No change to 2019 production forecast or capital budget

World Class ResourceMontney Pure Play

(1) As at December 31, 2018; see Advisories Section

(2) RLI (Reserve Life Index) is calculated using 2018 reserves divided by Q4 2018 annualized production volumes of 315 MMcfe/d (52,453 boe/d)

10

Natural Gas Pipeline

Coastal GasLink Pipeline

Asset• The Montney is the most economic

natural gas and natural gas liquids

play in Canada

• 292 net sections (186,727 net acres) of Montney lands

• 6.9 Tcfe (1,147 MMboe) Total Proved

Plus Probable Reserves(1) with 1.0 Tcfe

of Proved Developed Producing

reserves

Strategic Advantages• Firm transportation in-place allowing

access to a diversity of markets,

reducing commodity pricing risk

• De-risked reserves with deep

inventory of future drilling locations

2019 Capital ProgramDisciplined Capital Investment

• Current PONY budget maintains net capital spending within

adjusted funds flow from operations

• Investing $80 - $95 million for the year

• Forecast annual average daily production volume of

294 MMcfe/d (49,000 boe/d) to 306 MMcfe/d (51,000 boe/d)

• Program includes:

• Drilling 13 wells

• Completing 12 wells

• Estimated $4.3 million D&C costs assuming standard lateral well design of 1,800 meters

($4.9 million DCE&T)

2019 pricing based on WTI US$60/bbl, NYMEX USD$2.90/MMBtu, AECO CAD$1.90/Mcf, F/X CAD$0.76

11

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

• on PONY lands with up to 1.8x over-pressured reservoir

• liquids cut of approximately 9% of production volumes during Q3 2019

• high liquids production of approximately 20%

at Townsend with potential at Beg and Jedney

• liquids production over a total of

approximately 100,000 acres or 50% of acreage

Townsend

Kobes

Blair

Daiber

Beg

West

BlairCypress

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

12

South

Townsend

-

250,000

500,000

750,000

1,000,000

1,250,000

1,500,000

1,750,000

2,000,000

2,250,000

Source: GeoScout; As at March 6, 2019

57 of top

100 wells

are PONY

wells!

Top 100 Wells - Northern Montney Field (sample set of 1,394 wells)

Cum

ula

tive N

atu

ral G

as

(Mcf)

Painted Pony

Other Producers

The Sweet SpotNorth Montney 6-Month Cumulative Production Volumes

13

PONY has the best well

in North Montney with

6-month average daily

production rate of more

than 11 MMcf/d

16 of top

20 wells

are PONY

wells

British

Columbia

North

Montney PONY

• 1.0 Tcfe of PDP reserves

• 19% annual growth of PDP reserves at a cost of $0.55/Mcfe

• 31% annual growth of PDP NGLs to 14 MMbbls

• PDP reserve additions replaced 222% of annual production

• 3.1 Tcfe of 1P(1) reserves, including 38 MMbbls of NGLs

• 6.9 Tcfe of 2P(2) reserves, including 83 MMbbls of NGLs

• Average per well booking increased by 16% or 1.3 Bcfe to

9.2 Bcfe per well

• Reduced 1P(1) Future Development Capital by $308 million

• Reduced 2P(2) Future Development Capital by $657 million

2018 ReservesSignificant Resource, Significant Value

14

3.8 Tcfe

1.0 Tcfe

2.1 Tcfe

ProbableProven

Undeveloped

Proven DevelopedProducing (14% of Reserves)

3.1 Tcfe of

Total 1P(1)

Reserves

6.9 Tcfe of

Total 2P(2)

Reserves

(1) Total 1P – Total Proved

(2) Total 2P - Total Proved Plus Probable

2018 ReservesConsistently Profitable Recycle Ratios

15

3.1x

1.7x

2.8x

3.7x

0.0x

1.0x

2.0x

3.0x

4.0x

Proved DevelopedProducing

Total Proved Proved Plus Probable

2018 3-Year Weighted Average

2018 Corporate Netback

$1.71/Mcfe

PDP Finding, Development

& Acquisition Cost

$0.55/Mcfe

= 2018 PDP

Recycle Ratio

nmf

= 3.1x

(2016 - 2018)

Industry leading

PDP recycle ratio

nmf

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

Pro

ved p

lus

Pro

bable

Rese

rves

(Tcf)

4

6

8

10

12

2

2018 Natural Gas ReservesFourth-Largest 2P Natural Gas Reserves

6.4

11.7

9.6

7.3

5.1

4.64.1 4.0

2.6 2.4 2.2 2.1 1.9 1.9

1.1 1.0 0.9

0.3 0.3 0.3 0.2

Source: Company Reports; TD Securities / excludes NGLs and crude oil

16

Proved

Probable

4th largest natural gas

reserves of any publicly-

traded company in

Canada

Upper

Montn

ey

Mid

dle

Montn

ey

Low

er

Montn

ey

~ 3

30 m

Townsend Blair Beg

Productive Montney Layers

De-Risked Montney LayersProspective Montney Layers

Development HorizonsSignificant Unrealized Upside Across 7 Layers of Montney Resource

Doig formation

17

~ 2

90 m

Belloy formation

31 2 4 5 6

6

5

4

3 2

1Deep inventory of untapped Montney

opportunities across PONY’s 292 net sections

Canbriam TransactionClosed June 2019

18

• Canbriam Energy sold for $1 billion

• Offsetting acreage analog for PONY

• Validates land sale prices in NEBC

Montney Landholdings

Painted Pony Energy (186,727 net acres)

Canbriam Energy (171,436 net acres)

Major Gas Pipelines

Alaska Highway

Canbriam Deal Research Commentary Sell-Side PONY Analysis

“… With thrice the reserves carried by Canbriam, more than 6.0 Tcfe of proved and probable reserves, a multi-decade

drilling inventory and proximity to westbound pipe, Painted Pony remains the most logical next target for LNG players

looking for incremental supply ahead of project FID or construction… While LNG projects may still be a 2023/2024

catalyst, we do expect both LNG players and BC utilities to begin to scramble to lock up supply given the metrics paid

for Canbriam and expectations for a tighter gas market in NEBC go forward. In this vein, we expect PONY to announce

accretive long term gas supply agreements before year-end similar to the company’s Methanex deal that will materially

lower corporate risk and boost cash flow estimates for 2020 and beyond and potentially return momentum to the name.

A long term hold and core name, we believe Painted Pony is the purest way to play the LNG trade over the next five

years with near term catalysts and an attractive valuation…” July 26, 2019

Garett Ursu

Research Analyst

Cormark Securities

“… While each of the above [western Canadian gas-weighted] companies has unique characteristics that impact the

comparability to Canbriam … we believe that the implied transaction valuation is positive for the sector given the

relative strength of the metrics compared to those of publicly traded producers.…” July 29, 2019

Cameron Bean

Research Analyst

Scotiabank

“… We estimate that the deal value mapped to $1.0 billion based on Suncor’s Q2/19 disclosures, with metrics generally

favourable when compared to public companies. We don’t expect these metrics to come as a surprise to investors, but

provide an additional data point in what has been a quiet M&A environment.…” July 29, 2019

Michael Harvey

Research Analyst

RBC Capital Markets

19

Land Acres Valuation Equity Valuation

171,436 acres = $5,833/acre 186,727 $1,089 mm $769 mm $4.78/sh

Production

Q1 2019 Q1 2019 Value/boe/d Equity

36,953 boe/d = $27,061/boe/d 54,389 boe/d $1,470 mm $7.11/sh

YE 2018 Reserves

Reserves Purchase Price/boe Reserves Implied Value Value/share

PDP 76 MMboe = $13.14/boe 159 MMboe $1,757 mm $10.91/sh

1P 230 MMboe = $4.34/boe 511 MMboe $1,893 mm $11.76/sh

2P 408 MMboe = $2.45/boe 1,147 MMboe $2,485 mm $15.43/sh

Annualized Q1 2019 EBITDA Multiple

Ann. EBITDA=$150 mm = $1,000/$150 = 6.7x Ann. EBITDA = $212 mm x 6.7 = $8.82/sh

Canbriam Energy Transaction$1 Billion Transaction

Canbriam PONY

20Source: Canbriam June 2019 Corporate Presentation; Suncor owned 37% of Canbriam and disclosed the transaction value in their Second Quarter 2019 financial results

Land ValuationLand Sales Suggest PONY Undervalued

• The weighted-average price per acre

of land transactions for the past two

years for Montney parcels is

$4,703/acre

• 2019 corporate sale of Canbriam

Energy to Pacific Oil & Gas (a west

coast LNG exporter) further verifies

NEBC Montney value with 171,436

acres selling for $5,833/acre

• PONY’s 186,727 net Montney acres

carry an implied value, using recent

weighted-average per acre values,

of approximately $878 million

21

Montney Landholdings

Painted Pony Energy

Petronas

ConocoPhillips

Tourmaline Oil

Canbriam Energy

Saguaro Resources

CNRL

Black Swan Energy

Crew Energy

Storm Resources

Kelt Exploration

ARC Resources

Leucrotta Exploration

Todd Energy

NEBC Montney

Major Gas Pipelines

Alaska HighwayBernadet

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

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

Bernadet $9,095/acre (4,618 acres)$42 million / June 2018

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

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

$77 million / July 2017

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

Market DiversificationHigher Prices for Natural Gas

Dawn

NYMEX

PONY Sales /

Pricing Exposure

Medicine

Hat

AECO

Station

2

Sumas

22

LNG

Export

Mexico

Export

U N I T E D S T A T E S

C A N A D A

M E X I C O

PONY

Growing US Natural Gas ExportsExports to Mexico 5.2 Bcf/d

LNG forecast year-end 2019 8.2 Bcf/d

2020 LNG additions 1.6 Bcf/d1Total (end 2020) 15 Bcf/d

1 GMP FirstEnergy Forecast – October 2018

MEDICINE HAT

14-year contract (began in 2017)

for PONY to deliver 10 MMcf/d to

Methanex’s methanol plant in

Alberta increasing to 20 MMcf/d

in 2021 and 50 MMcf/d in 2023

SUMAS Market

22 MMcf/d 2019

average (spot)

AECO Market132 MMcf/d 2019 average(fixed price & spot)

St 2 Market29 MMcf/d 2019 average(spot)

NYMEX Basis Contracts

45 MMcf/d 2019 average

DAWN Market

45 MMcf/d 2019 average

88 MMcf/d as of Nov 2019

(fixed price & spot)

Market DiversificationManaging Volatility

45% of PONY’s fourth quarter

2019 production revenue is

protected through a

combination of physical and

financial fixed-price contracts

at a volume-weighted average

price of $4.51/Mcfe

(average of $3.14/Mcf for natural gas

and $71.23/bbl for liquids)

23

Expected 2019 Q4 Production

Revenue by Source

SUMAS

DAWN

NYMEX

17%

12%

10%

18%

18%

12%

3%

11%

44%

NGLs$71.23/bbl

DAWN$3.70/Mcf

AECO / STN 2$2.47/Mcf

56%

AECO / STN 2

25

26%

10%

22% 24%

9%

25%

31%

37%40%

34%

10%

17%

18%

19%

16%

11%13%

11%

12%

12%

27% 29%

12%5%

29%

0%

10%

20%

30%

40%

50%

60%

70%

80%

90%

100%

Q4 2019 Q1 2020 Q2 2020 Q3 2020 Q4 2020

Natu

ral G

as

Volu

me N

et

Exposu

re b

y H

ub (

%)

Note: Percentages as of September 30, 2019

2020 annual production guidance has not been disclosed. 2020 annual production percentages assume flat annual production 2019 to 2020

AECO / ST 2 Sumas Index Dawn Index NYMEX Index

PONY regularly adds new contracts as part of ongoing risk

management through sales hub diversification

Sales DiversificationPONY’s Net Exposure of Physical and Financial Contracts

Transportation Firm Transportation & Toll Advantage to West Coast

Enbridge T-North Tolls

• Single toll structure

• $0.24/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

• $0.19/Mcf delivery off AECO

• $0.81/Mcf delivery into Dawn

25

LNG Canada Export Terminal at Kitimat, BC

“…The purpose of the proposed

Project is to connect natural

gas producing areas in

northeast BC with the proposed

LNG Canada export facility near

Kitimat, BC, to access new

global natural gas markets…”

- Appendix F, Section 1; Coastal GasLink

Pipeline Project; Environmental Assessment

Certificate Application; Section 1.2.1

“Purpose of the Proposed Project”; page 3

PONY has a net $0.22/Mcf

transportation toll

advantage delivering

natural gas to Sunset Creek

(start of the Coastal

Gaslink pipeline) over

natural gas sourced in

Alberta due to AECO tolls

$3.10/Mcfe

2019f

Cost StructureChallenging Commodity Price Environment

($0.53)

($0.79)

($0.15)

($0.23)

($0.52)

$0.64

26*2019 pricing based on WTI US$60/bbl, NYMEX USD$2.90/MMbtu, AECO CAD$1.90/Mcf, F/X CAD$0.76

Townsend

Processing

Interest

G&A

Transportation

Operating

Cost

$0.76Forecasted Adjusted

Funds Flow from

Operations/McfeRoyalties ($0.06)Carbon Tax ($0.06)

2019 Top Line Revenue (forecasted*, includes Q1, Q2, Q3 actuals)

$0.12Hedging Gain

Adjusted Funds Flow

from Operations

$2.34Forecasted Cash

Expenses

$0

$2,000,000

$4,000,000

$6,000,000

$8,000,000

$10,000,000

$12,000,000

$14,000,000

Dri

ll a

nd C

om

ple

tion C

ost

($)

2,600 meter lateral well cost (drill + complete cost)

Perf & Plug Systems21 wells

D&C cost $7.7 million

2011 2012 2013 2014 2015 2016 2017

1st Generation Open

Hole Ball Drop System33 wells

D&C cost $6.9 million

Current Generation Open Hole Ball Drop

System

126 wellsD&C cost $4.3 million

As capital well costs fell, production type curves

dramatically improved

Management

Type Curve

increased

50%

well cost (drill + complete)

Historical CostsDrilling & Completions Efficiency

27

2018

$4.3 mm

average

(1) Total 2P - Total Proved Plus Probable

2019

Continued type curve

improvement with

average Total 2P(1) well

booking of 9.2 Bcfe/well

0

1,000

2,000

3,000

4,000

5,000

6,000

7,000

8,000

9,000

0 10 20 30 40 50 60 70 80 90 100 110 120 130 140 150 160 170 180 190 200

1,800 m standard lateral management type curve

Blair Long Lateral WellsEncouraging Performance

2,600 m lateral (202/c-038/094-B-16/00)

2,600 m lateral (200/c-038-F/094-B-16/00)

28

Using longer laterals PONY

has the opportunity to

improve capital efficiency

by approximately

$2,000/boe/d

Producing 2,600 m lateral wellsDrilled awaiting completion 2,600 m lateral

Blair

Daiber

Townsend

South

Townsend

Beg

Jedney

West

Blair

Cypress

Kobes

202/c-038/094-B-16/00

and

202/c-038/094-B-16/00

Wells choked

initially for sand

production

Well chokes

70%-80%

open

Both wells

completed with 30

stages using 0.85

tonnes/meter

Longer lateral wells drilled

into Upper Montney have

outperformed standard

lateral length wells

Days on Production (209 days total as at Sept 28, 2019)

Cale

ndar

Day N

atu

ral G

as

Rate

(M

Mcf/

d)

Single Well Economics* IRR NPV10 Pay Out

Daiber 1,800 m lateral(dry)

52% $5.1 mm 1.9 years

Daiber 2,700 m lateral(dry)

74% $8.8 mm 1.5 years

Blair 1,800 m lateral (lean; 15 bbls/MMcf)

47% $5.0 mm 2.0 years

Blair 2,700 m lateral (lean; 15 bbls/MMcf)

74% $9.0 mm 1.5 years

Townsend 1,800 m lateral(liquids-rich; 47 bbls/MMcf)

31% $2.5 mm 2.7 years

Single Well Economics by AreaDriving Increased Capital Efficiencies Through Longer Lateral Wells

*Single well economics based on $60/bbl WTI; $1.90/Mcf AECO; USD/CAD $0.76

29

Well Capital Costs

1,800 meter lateral

Drilling $2.2 million

Completion $2.1 million

Equip and Tie-in $0.6 million

Total $4.9 million

2,700 meter lateral

Drilling $2.3 million

Completions $2.9 million

Equip and Tie-in $0.6 million

Total $5.8 million

PONY’s recent longer laterals deliver higher rates of

return than previous standard length laterals drilled to

1,800 meters. Based on improved performance PONY

recently drilled a 3,000+ meter lateral well

0.0087

0.0076

0.0064

0.00410.0033

0.0000

0.0020

0.0040

0.0060

0.0080

0.0100

2014 2015 2016 2017 2018

tonnes

CO

2e/boe

• PONY is committed to reducing GHG emissions through deliberate actions which produce measurable improvements

year after year, as evidenced by the 62% reduction in tonnes of CO2 emitted per boe since 2014

• PONY recycled 94% of flow back water during 2018 which greatly reduced the amount of fresh water taken from

surface sources needed to complete wells

• Participate in a ‘Water Co-operative’ with other producers in operating areas to share completion water further

reducing fresh water use

ESG Environmental, Social, Governance

Environmental

• In 2019 PONY began using natural gas to power

completion operations, further reducing CO2

emissions by replacing diesel as a fuel source

• Through rigorous maintenance and inspections of

our well-site vents to ensure optimal

functionality combined with use of best available

seals and actuator technology, PONY has been

consistently reducing year-over-year CO2

intensity in field operations to one of the lowest

in the industry

CO2 Emissions Reduction

Water Use Reduction

30

PONY strives to:

Grow relationships with local Indigenous neighbours to instill trust and earn support for current and

future operational activities

Strengthen employee effectiveness to create a culture of awareness and promote cohesiveness when

working with our Indigenous neighbours

Increase local Indigenous opportunities for employment and contracts that deliver mutual benefits and

promote sustainability

Painted Pony delivering Christmas Hampers to

Halfway River First Nation

PONY CEO, Pat Ward, speaking to the

First Nations Field Operator Class

ESG Environmental, Social, Governance

Social – Indigenous Relations

31

• Institutional Shareholder Services Inc. (ISS) is the world’s leading provider of

corporate governance and responsible investment ratings. On a 1-10 scale

where 1 is excellent and 10 is deficient, Painted Pony received a quality

score of ‘1’ in 2019, highest in our peer group of companies.

• Painted Pony has developed and implemented a complete portfolio of corporate

policies including:

• Code of Ethics

• Corporate Disclosure

• Health, Safety and Environment

• Whistleblowing

• Respectful Workplace

• Compensation Clawback

• Insider Trading

• Director and Officer Share Ownership

• Painted Pony believes in diversity and this is reflected by the three women on

the Board of Directors, with two chairing Board committees • Joan Dunne, Chair of Audit & Risk Committee

• Lynn Kis, Chair of Reserves & HSE Committee

• Betsy Spomer

• PONY’s board is 33% women, double the average for all TSX-listed companies of 16.4%*

ESG Environmental, Social, Governance

Governance

*Source: 2019 Diversity Disclosure Practices – published by Osler, Haskin & Harcourt

32

Well situated to supply Canadian west coast LNG projects

Diversified Market Access and Sales Points

Massive reserves base

Top well performance

Industry leading PDP recycle ratio at 3.1x

Recent adjacent transaction shows significant upside value

Strong ESG Performance

Pony PointsChecking Off All of the Boxes

33

Appendices

&

Advisories

Financial Strength Term Debt and Credit Facility Provide Financial Flexibility

$375 Million Syndicated Credit Facility• Secured, Reserve Based Lending

• Matures May 2021

• $120 million drawn as at November 8, 2019

$144 Million Term Debt (Senior Unsecured Notes)

• Held by Magnetar Capital

• 8.5% Coupon

• $150 million maturity in 2022

• Not callable until August 2020

$47 Million Subordinated Convertible Debentures• Held by Magnetar Capital

• 6.5% Coupon

• $5.60 Conversion Price

• $50 million maturity 2021 (subject to any conversion)

• ‘No Shorting’ Provision included

Debt Capital

Diversification

Syndicated

Credit Facility

Drawn (as at November 8, 2019)

Undrawn (excluding Letters of Credit)

Senior Notes

Convertible Debentures

Drawn on Credit Facility

$255

$120

$120

$144

$47

34

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

Equity ResearchSell-Side Analyst Coverage

35

Auditor KPMG LLP

Evaluation Engineers GLJ Petroleum Consultants Ltd.

Banks

Transfer Agent

The Toronto-Dominion Bank

Canadian Imperial Bank of Commerce

The Bank of Nova Scotia

Alberta Treasury Branches

Royal Bank of Canada

HSBC Bank Canada

TSX Trust Company

Corporate Office

Suite 1200, 520 – 3rd Avenue SW

Calgary, Alberta T2P 0R3

Toll Free Investor 1 (866) 975-0440

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

Email: info@paintedpony.ca

www.paintedpony.ca

Corporate Overview

36

This presentation contains a summary of management’s assessment of results and should be read in conjunction with the Financial Statements and related Management’s Discussion and Analysis for the quarter

ended September 30, 2019, 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; (x) the

availability of LNG export facilities; (xi) global LNG demand; and (xii) natural gas consumption. 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. There is ongoing litigation involving the Blueberry River First Nation ("BRFN") and the British

Columbia government regarding the obligations of natural resource companies and the Crown relative to the adequacy of consultation and cumulative effects in respect of upstream oil and gas development in

northeast British Columbia, where a substantial portion of the Corporation’s land and assets are situated. The Corporation is not a party to the litigation. While a successful claim by BRFN may be adversely

material to the Corporation, at this point, the success of the claim and any corresponding impact is indeterminable. If the claim is decided in BRFN’s favour, it would have an adverse impact on the

Corporation, its operations and production, particularly for those operations that may be considered to impact Aboriginal traditional lands or rights. The Corporation is therefore, actively monitoring the status

of the BRFN claim. 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 year ended December 31, 2018 and the quarter ended September

30, 2019.

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.

Advisory

3

1

Non-GAAP Measures: This presentation may make reference to the terms “adjusted funds flow from operations”, “adjusted funds flow from operations per share”, "corporate netback" and “net debt”, which do

not have standardized meanings prescribed by IFRS and therefore may not be comparable with the calculation of similar measures presented by other issuers. Management of the Corporation believes these

measures are useful supplemental measures of the net position of current assets and current liabilities of the Corporation and the profitability relative to commodity prices. Readers are cautioned, however, that

these measures should not be construed as alternatives to other terms such as current and long-term debt or comprehensive income determined in accordance with IFRS as measures of performance. The

Corporation's method of calculating these non-GAAP measures may differ from other companies, and accordingly, may not be comparable to similar measures used by other entities.

Management uses “adjusted funds flow from operations” to analyze operating performance and considers adjusted funds flow from operations to be a key measure as it demonstrates the Corporation’s ability to

generate the cash necessary to fund future capital investment and to repay debt. Adjusted funds flow denotes cash flow from operating activities before the effects of changes in non-cash working capital and

decommissioning expenditures. “Adjusted funds flow from operations per share” is calculated using the basic and diluted weighted average number of shares for the period. These terms should not be considered

alternatives to, or more meaningful than, cash flows from operating activities as determined in accordance with IFRS as an indicator of the Corporation’s performance.

Management uses “net debt” as useful supplemental measures of the liquidity of the Corporation. Net debt is calculated as bank debt, senior notes, liability portion of convertible debentures, and working capital

(deficiency), adjusted for the net current portion of fair value of risk management contracts and current portion of finance lease obligation. These terms should not be considered alternatives to, or more

meaningful than, current and long-term debt as determined in accordance with IFRS.

"Corporate netback" is used as a supplemental measure of the Corporation's profitability relative to commodity prices. Corporate netback is calculated on a per unit basis as natural gas and natural gas liquids

revenues, adjusted for realized gains or losses on risk management contracts, less royalties, operating expenses, transportation costs and finance lease expense. This term should not be considered alternatives to,

or more meaningful than net income (loss) and comprehensive income (loss) as determined in accordance with IRFS. Included in this presentation are estimates of the Corporation’s 2019 adjusted funds 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 December 2018 and are

included to provide readers with an understanding of the Corporation’s anticipated adjusted funds flow based on the capital expenditures and other assumptions described. Readers are cautioned that the

information may not be appropriate for other purposes.

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, 2018 and dated March 5, 2019. Before tax net present values set forth herein are based on a 10 percent discount rate and

GLJ’s January 1, 2019 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.

3

2

Advisory

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; and

c) Possible Reserves are those additional reserves that are less certain to be recovered than probable reserves. It is unlikely that the actual remaining quantities recovered will exceed the sum of the

estimated proved plus probable plus possible 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 (e.g. 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.

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).

3

3

Advisory