Investor Update

March 18, 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

2

Billion T

oe

(tonnes

of

oil e

quiv

ale

nt)

Oil

Natural Gas

Coal

Perc

enta

ge o

f G

lobal

Energ

y N

eeds

Corporate ProfileTSX: PONY

3

3-Year Growth Profile104% Increase in Adjusted Funds Flow Per Share ● 149% Production Volume Increase

Forecasted 2019 Production324 - 336 MMcfe/d (54,000 – 56,000 boe/d)

Balance Sheet1.4x Net Debt : Q4 2018 Annualized EBITDA

Trading Metrics900k shares per day (60 day average) ● $300 million market capitalization ● 161 mm shares

*

* As at March 14, 2019

2018 Highlights Take Aways

4

Strong Production Volumes and Free Funds

Flow

• 35% Annual production volume growth to 347 MMcfe/d (57,879 boe/d)

• 43% Annual liquids production growth to 5,128 bbls/d (45% Condensate)

• $154 million Capital Investment

• $175 million annual Adjusted Funds FlowValue-Added Reserves

• 19% Proved Developed Producing Growth with a 3.1x Recycle Ratio

• 31% Proved Developed Producing Liquids Growth

• $308 million (17%) reduction in Total Proved FDC

• $657 million (16%) reduction in Total Proved Plus Probable FDC

• $0.55/Mcfe Total Proved Developed Producing FD&A cost

Sales Diversification Strategy Increases Netback

• 2018 realized natural gas price 69% higher than AECO 5A spot

• Q4 realized natural gas price 150% higher than AECO 5A spot

• 78% of 2018 natural gas production volumes priced outside of AECO and Station 2

• 50% of 2019 revenue protected through physical and financial hedges

Global LNG MarketSupply Shortage / Growth Demand

Source: GMP FirstEnergy, IHS Energy, Bloomberg5

$2.00

$4.00

$6.00

$8.00

$10.00

$12.00

India Spain Japan UK

Global LNG Netbacks

Bcf/

d

USD

$/M

MBtu

Global LNG market is facing additional

tightness in 2019 as demand growth

continues to outstrip supply growth

Global LNG prices have been increasing in-

line with the realized and forecasted

increases in the LNG demand curve

0.0

2.0

4.0

6.0

8.0

10.0

Jan

-15

Mar

-15

May

-15

Jul-

15

Sep

-15

No

v-15

Jan

-16

Mar

-16

May

-16

Jul-

16

Sep

-16

No

v-16

Jan

-17

Mar

-17

May

-17

Jul-

17

Sep

-17

No

v-17

Jan

-18

Mar

-18

May

-18

Jul-

18

Sep

-18

Monthly Chinese LNG Imports

177% increase in

Chinese LNG imports

since 2015

6

Proposed West Coast LNG & LPG ProjectsGame Changer

AltaGas Ridley Island

Propane Export

Terminal

40,000 bbl/d export

(Under Construction)

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 early 2019)

~0.3 – 1.0 Bcf/d

Kitimat LNGChevron / Woodside

~1.6 – 3.5 Bcf/d

Jordan Cove LNGPembina Pipeline Corp.

~1.0 – 1.6 Bcf/d

TOTAL ~4.5 – 9.9 Bcf/d

British Columbia

Alberta Natural Gas MarketContinued Demand Growth

Source: GMP FirstEnergy, CAPP, AER7

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 2030

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

Electricity Generation Sources in

Alberta

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)

Asset • The Montney is the most economic natural gas and

natural gas liquids play in Canada

• 305 net sections (195,187 net acres) of Montney lands

• 6.9 Tcfe (1,147 MMboe) Total Proved Plus Probable

Reserves(1) with a Total Proved Plus Probable RLI(2) of

60 years

• 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

Sustainable Capital Investment• 2019 cash flow budget focuses on preserving financial

flexibility and maintaining capital discipline

8

Natural Gas Pipeline

Coastal GasLink Pipeline

British Columbia

Alberta

Washington

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 average of approximately 9% of production volumes during 2018

• 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 land base

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

9

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, 2018

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

10

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

Townsend Blair Beg

Upper

Montn

ey

Mid

dle

Montn

ey

Low

er

Montn

ey

330 m

Productive Montney Layers

De-Risked Montney LayersProspective Montney Layers

A A’

Development HorizonsSignificant Unrealized Upside Across 7 Layers of Montney Resource

31 2 4 5 6

6

5

4

3 2

1

Deep inventory of

untapped Montney

opportunities across

PONY’s 305 net sections

Belloy formation

Doig formation

290 m

11

• 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 Total 1P(2) reserves, including 38 MMbbls of

NGLs

• 6.9 Tcfe of Total 2P(3) reserves, including 83 MMbbls of

NGLs

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

9.2 Bcfe per well resulting in 111 fewer Total 1P(2) wells

and 141 fewer Total 2P(3) wells

• Positive revisions reduced 1P(2) FDC(1) by $308 million

• Positive revisions reduced 2P(3) FDC(1) by $657 million

2018 ReservesSignificant Resource, Significant Value

12

3.8 Tcfe

1.0 Tcfe

2.1 Tcfe

ProbableProven

Undeveloped

Proven DevelopedProducing (14% of Reserves)

3.1 Tcfe of

Total 1P(2)

Reserves

6.9 Tcfe of

Total 2P(3)

Reserves

(1) FDC – Future Development Capital

(2) Total 1P – Total Proved

(3) Total 2P - Total Proved Plus Probable

2018 ReservesConsistently Profitable Recycle Ratios

13

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

The reduction in Future

Development Capital (FDC(1)) by

$308 million for Total 1P(2) and

$657 million for Total 2P(3),

exceeded total 2018 capital

spending of $154 million.

Corporate Netback*

$1.71/Mcfe

PDP Finding, Development

& Acquisition Cost

$0.55/Mcfe

= 2018 PDP

Recycle Ratio

nmf

= 3.1x

(2016 - 2018)

* Corporate Netback includes the Townsend Facility capital lease fee of $0.45/Mcfe

Industry leading PDP recycle

ratio delivered returns through

corporate netbacks which

exceeded the cost of PDP

reserve additions in 2018 by a

factor of 3.1x

(1) FDC – Future Development Capital

(2) Total 1P – Total Proved

(3) Total 2P - Total Proved Plus Probable

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 195,187 net

acres (305 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 195,187 net acres carry an

implied value, using recent

weighted-average per acre values, of

approximately $920 million

PONY

Progress

ConocoPhillip

s

Saguaro

Kelt

Canbriam

Black Swan

Storm

Tourmaline

CNRL

Todd

14

Market Diversification & Growing US Exports Higher Prices for Natural Gas; PONY 2018 Realized Price 69% Higher than AECO 5A

Chicago

LNG Export

Dawn

NYMEX

Mexico Export

PONY Sales / Pricing

Exposure

Medicine

Hat

AECO

1 GMP FirstEnergy Forecast – October 2018

Forecast year-end 2019 8.2 Bcf/d

2020 Additions 1.6 Bcf/d1Total (end 2020) 9.8 Bcf/d

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

MEDICINE HAT

14-year contract to deliver

10 MMcf/d to Methanex

Corporation’s methanol plant

in Medicine Hat, Alberta

increasing to 20 MMcf/d in

2021, and 50 MMcf/d in 2023

and for the duration

Current Exports 5.2 Bcf/d

DAWN Market45 MMcf/d 2019 average

88 MMcf/d beginning Nov 2019 (fixed price & spot)

SUMAS Market22 MMcf/d 2019 average(spot)

NYMEX Market45 MMcf/d 2019 average(basis contracts)

Station

2

Sumas

15

St 2 Market29 MMcf/d 2019 average(spot)

Transportation Firm Transportation & Toll Advantage to West Coast

(increases to 90 MMcf/d Nov

2019)

Enbridge T-North Tolls

• Single toll structure

• $0.22/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

16

“…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

Canada LNG Export Terminal at Kitimat, BC

$3.22/Mcfe

2019f

Cost StructureChallenging Commodity Price Environment

($0.57)

($0.74)

($0.13)

($0.22)

($0.48)

$0.95

2018 adjusted funds

flow per Mcfe showed

the strength of

PONY’s diversified

marketing strategy

17

$3.19/Mcfe (1)

2018 Actual Top

Line Revenue (excluding realized hedging)

2018

($0.51)

($0.71)

($0.13)

($0.20)

($0.45)

$1.08

$0.30

2019 pricing based on WTI US$60/bbl, NYMEX USD$3.23/MMbtu, AECO CAD$1.90/Mcf, F/X CAD$0.75

Townsend

Processing

Interest

G&A

Transportation

Operating

Cost

$1.38Adjusted Funds

Flow /McfeCash Flow

(pre-hedging)

$0.89Adjusted Funds

Flow/Mcfe

Royalties ($0.05)Carbon Tax ($0.06)

Hedging Loss ($0.06)Royalties ($0.07)Carbon Tax ($0.06)

Hedging Gain

2019 Forecasted

Top Line Revenue (excluding realized hedging)

2019 Production RevenueManaging Volatility

50% of PONY’s 2019 production

revenue is protected through a

combination of physical and

financial fixed-price contracts

at a volume-weighted average

price of $4.84/Mcfe

(average of $3.39/Mcf for natural gas and

$70.62/bbl for liquids)

18Volumes not under contract are presumed to be sold at December 4, 2018 index pricing

Expected 2019 Production

Revenue by Source

SUMAS

DAWN

AECO

NYME

X

NGLs

18%

6%

2%

8%

11%

5%

21%

6%

3%

6%

12%

50%

NGLs$70.62/bbl

DAWN$3.99/Mcf

STATION 2$2.60/Mcf

AECO$2.98/Mcf

50%

2%

Production ProfileProfile Optimizes Balance Sheet Flexibility

2015 94 MMcfe/d

(15,604 boe/d)

2016139 MMcfe/d

(23,204 boe/d)

2017257 MMcfe/d

(42,882 boe/d)

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

19

2018347 MMcfe/d

(57,879 boe/d)

0

1

2

3

4

5

0

50

100

150

200

250

300

350

400

Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 Q1f Q2f Q3f Q4f

Quart

erl

y A

vera

ge D

aily P

roducti

on

(Mcfe

/d)

Quarte

rly A

vera

ge D

aily

Pro

ductio

n P

er S

hare

(Mcfe

/sh

are

)

566% forecast

increase in

annual average

daily production

(2013 –2018)

Enbridge

T-South

disruption

2014 79 MMcfe/d

(13,192 boe/d)

2013 52 MMcfe/d

(8,693 boe/d)

Quarterly production per share

Quarterly average daily production (actual)

Quarterly average daily production (forecast)

2019f324-336 MMcfe/d

(54,000-56,000 boe/d)

$31 $107 $53 $204 $109 $303 $1750

100

200

300

400

500

$0

$50

$100

$150

$200

$250

$300

$350

$400

Capital Spending & Adjusted Funds FlowImpressive Per Share Adjusted Funds Flow Growth

2015 2017

5.6x 2.2x 1.4x

20182016

2.0xNet Debt to

Q4 Annualized

EBITDA

$0.53/

share

$0.78/

share

$1.08/

share

$0.31/

share

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

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

347 MMcfe/d(57,879 boe/d)

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

36% CFPS

Growth

Annual Average Daily Production Volumes

Capital Spending

Free Adjusted Funds Flow(1)

Adjusted Funds Flow(1)

$21

20

$154

$21 million

free adjusted

funds flow

(1) Net of Interest Expense, G&A, Capital Lease Expense, and Share Unit Expense

2019 Capital Program‘Cash Flow Budget’

• ‘Cash Flow Budget’ - matching capital spending with

internally generated adjusted funds flow

• Investing $95 - $110 million

• Forecast annual average daily production volume of

324 MMcfe/d (54,000 boe/d) to 336 MMcfe/d (56,000 boe/d)

• Program includes:

• Drilling 19 wells

• Completing 18 wells

• Estimated $4.2 million D&C costs

($4.75 million DCE&T)

2019 pricing based on WTI US$60/bbl, NYMEX USD$3.23/MMBtu, AECO CAD$1.90/Mcf, F/X CAD$0.7521

$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 System33 wells

D&C cost $6.9 million

Current Generation Open Hole Ball Drop

System

117 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 Total 2P(1) well

booking of 9.2 Bcfe/well

22

2018

$4.2 mm

average

(1) Total 2P - Total Proved Plus Probable

-

1,000

2,000

3,000

4,000

5,000

6,000

7,000

8,000

Single Well Economics IRR NPV10 Pay Out

Daiber (dry)

49.9% $4.7 mm 23 months

Blair (lean; 15 bbls/MMcf)

55.7% $5.9 mm 23 months

Townsend (liquids-rich; 36 bbls/MMcf)

32.7% $2.8 mm 31 months

Capital Costs

Drilling $2.1 million

Completions $2.1 million

Equip / Tie-in $0.55 million

TOTAL $4.75 million

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: $60/bbl WTI; $1.90/Mcf AECO; USD/CAD $0.75; Standard well design

6 months 12 months

23

0

20

40

60

80

100

120

140

160

180

$1.75 $2.00 $2.25 $2.50 $2.75 $3.00

Rate

of

Retu

rn (

% B

T)

AECO ($/Mcf)

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

Pricing Flat at: $60/bbl WTI; USD/CAD $0.75

*$1.90/Mcf Consensus pricing; 2019 Capital Budget assumption

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

24

$1.90*

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

Attractive relative valuation

Pony PointsChecking Off All of the Boxes

25

Appendices & Advisories

Financial Strength Term Debt and Credit Facility Provide Flexibility

$400 Million Syndicated Credit Facility• Secured, Reserve Based Lending

• Matures May 2020

• $163 million drawn as at December 31, 2018

$143 Million Term Debt (Senior Unsecured Notes)• Held by Magnetar Capital

• 8.5% Coupon

• Mature in 2022

• Not callable until August 2020

$46 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

Undrawn

Senior Notes

Convertible Debentures

Drawn on Credit Facility (incl working capital)

$237 $163

$196$143

$46

26

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

27

Auditor KPMG LLP

Evaluation Engineers GLJ Petroleum Consultants Ltd.

Banks

Transfer Agent

The Toronto-Dominion Bank The Bank of Nova ScotiaAlberta Treasury BranchesCanadian Imperial Bank of CommerceRoyal Bank of CanadaHSBC Bank CanadaWells Fargo Bank

TSX Trust Company

Corporate Office

Suite 1200, 520 – 3rd Avenue SWCalgary, 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

28

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 December 31, 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 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. 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 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, and the BRFN and the Crown are currently in

negotiations. However, if the claim is decided in BRFN’s favour, the Corporation may incur increased costs relative to operations in northeast British Columbia, 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 quarter December 31, 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 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

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Non-GAAP Measures: This presentation makes reference to the terms “adjusted funds flow”, “adjusted funds flow per share”, “adjusted funds flow netbacks”, “free adjusted funds flow”, "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” to analyze operating performance and considers adjusted funds flow 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. “Adjusted funds flow

netbacks” is calculated using the average production volumes for the period. “Free adjusted funds flow” is calculated as adjusted funds flow less capital spending. 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.32

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.

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.

(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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Advisory