PAINTED PONY Investor January PETROLEUM LTD ...s2.q4cdn.com/513538771/files/doc_presentations/2017/Jan/...Presentation January 4, 2017 TSX: PPY Win / Win Relationships Long-Term Thinking

PAINTED PONY PETROLEUM LTD.

Investor Presentation

January 4, 2017 TSX: PPY

Win / Win Relationships

Long-Term Thinking

‘Always do the right thing’

Innovation

Antifragile

“Why” do we do what we do?

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

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

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

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

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

1

Debt (3) 208.7 million Shares Outstanding (2) 100 million

Corporate Profile

Ticker Symbol PPY TSX

Daily Production (1)

240 MMcfe/day (40,000 boe/d)

Daily Trading Volume (30 day trading average)

1.5 million shares per day

Market Capitalization

$900 million Syndicated Credit Facility

$325 million

(1) Average production volumes during first week of November, 2016 (2) As at September 30, 2016 (3) Comprised of bank debt and working capital deficiency; As at September 30, 2016 2

Significant Growth Montney

Growth • Current production of approximately 240 MMcfe/d (40,000 boe/d)

representing a 156% increase over fourth quarter 2015 average daily production of 93.6 MMcfe/d (15,604 boe/d)

• Fully funded with funds flow from operations and $325 million syndicated bank credit facilities

Asset • 100% BC Focused Montney

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

• 4.6 Tcfe (768 MMboe) Proved Plus Probable Reserves(1) (4.2 Tcf Natural Gas; 76 MMbbl liquids)

Strategic Advantages • Highly over-pressured, delineated, and tested Montney asset

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

• Current and proposed sales pipelines intersect PPY properties

• Firm transportation in-place to meet commitments from AltaGas Townsend Facility with 130 MMcf/d of incremental firm transportation directly into AECO available ~November 2017

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

3

The Montney Trend Location, Location, Location

PPY’s Montney Sweet Spot is:

• a dolomitic siltstone with higher quality reservoir than a shale

• 4x thicker than the Marcellus at greater than 300 meters (approximately 1,000 ft.) thick

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

• in a 1.8x over-pressured area

• a high heat-content natural gas play with value enhancing associated natural gas liquids up to 60 bbls/MMcf

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

• positioned with excellent pipeline egress to North American markets

4

Thick, over- pressured, sweet spot

300m (984 ft)

Production Growth Impressive and Consistent

Annu

al Aver

age Dai

ly Production (MMcfe/d) A

nnual Average MMcfe per Day

per 1 Million Shares

2017 Forecast Exit Production Volumes of

408 MMcfe/d (68,000 boe/d)

2016 Forecast Exit Production Volumes of

240 MMcfe/d (40,000 boe/d)

138

87 94

56 59

43

138 25.3 39.5 52.2 79.2 93.6

0

450

400

350

300

250

200

150

100

50

0

289

288

300

250

200

150

100

50

350

48,000 boe/d

Annual Average boe/d

4,221 boe/d

6,589 boe/d

8,693 boe/d

13,192 boe/d

15,604 boe/d

23,000 boe/d

2011 2012 2013 2014 2015 2016f 2017f

Oil and NGL Natural Gas Exit Production Production per Share Forecast Production per Share

• 57% Compound Annual Production Growth, 2011 – 2015 • 45% Compound Annual Growth in production per share, 2011 – 2015

• 1,060% Expected Absolute Growth in Production, 2011 - 2017 • 572% Expected Absolute Growth in Production per Share, 2011 - 2017 5

6

Proposed 5-Year Development Model Infrastructure Build Drives Production Growth

BOE/d

120,000

100,000

40,000

80,000

60,000

20,000

-

AltaGas Townsend Facility (Phase 1B)

48 MMcf/d Commitment

AltaGas Townsend Facility (Phase 2) 100 MMcf/d

23,000 (e)

2016

AltaGas Townsend Facility (Phase 3) 100 MMcf/d

AltaGas Townsend Facility (Phase 1A)

150 MMcf/d Commitment

48,000 (e)

2017

PPY Owned Facility 80 MMcf/d Expansion

72,000 (e)

2018

50 MMcf/d Expansion PPY Owned Facility

100,000 (e)

2019

PPY Owned Facility Expansion

60 MMcf/d

115,000 (e)

2020

2019

2020

2018

2017

2016

690 MMcfe/d (115,000 boe/d)

Avg. Daily Production (boe/d)

138 (e) 288 (e) 432 (e) 600 (e) 690 (e)

1,600 (e) 4,800 (e) 7,800 (e) 9,800 (e) 10,000 (e)

Avg. Daily Production (MMcfe/d)

Avg. NGL Production (bbls/d)

Growth Plan Increasing Cash Flow from Production Growth

$CAD (M

illi

ons)

$300

690 MMcfe/d (115,000 boe/d)

Capital Development Program (November 2016)

2016 2017 2018 2019 2020 2.0x 1.3x 1.2x 0.7x 0.2x

7

700

650

600

550

500

450

400

350

300

250

200

150

100

50 Annual

Aver

age Dai

ly For

ecast Pr

oduc

tion (MMcfe/d)

0

$600

$500

$400

$200

$100

$0

Year-End Net Debt to Q4 Annualized Cash Flow

600 MMcfe/d Free Cash Flow (100,000 boe/d)

432 MMcfe/d $220

(72,000 boe/d) $84

288 MMcfe/d (48,000 boe/d)

138 MMcfe/d (23,000 boe/d)

$287 $172 $56 $507 $213 $319 $430

Cash Flow (Net of Interest Expense and Capital Lease Finance Expense) (Based on Nov 1, 2016 Strip Pricing; see slide 10 for pricing)

Annual Average Daily Forecast Production

$385 $292 $346

Free Cash Flow Positive

beginning in 2019 at

Nov 1, 2016 strip pricing

2.5 2.3x 2.5

November 1, 2016 Strip Pricing

YE Net Debt

: Q4

Annu

alized C

ash

Flow

1.9x 2.0

1.5 1.2x

1.0

0.5

0.0 2016 2017

$3.25 Natural Gas NYMEX ($USD) (WTI and FX at November 1, 2016 Strip)

2.5

2.0

1.5

1.0

0.5

0.0

1.0x

0.4x

0x

2018 2019 2020

$2.25 Natural Gas NYMEX ($USD) (WTI and FX at November 1, 2016 Strip)

2.2x

1.9x 1.8x

1.6x

2.0

1.5

1.0

0.5

0.0 2016 2017 2018 2019 2020 2016 2017 2018 2019 2020

2.0x

1.3x 1.2x

0.7x

0.2x

Commodity Price Sensitivity Balance Sheet Strength Maintained

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

8

Increasing Cash Flow per Mcfe Driving Cash Costs Lower; Increasing Liquid Yields

9

2015 2016f 2017f

Lower Cash Costs Combine with

Increasing Liquids Yields to Drive

Higher Cash Flow Netbacks

2015 2016f 2017f

Operating Costs per Mcfe Liquids Production

n 6,000

(

Bbl

s/d

)

4,000

2,000

0

$0.93

48% reduction 481%

tio Liqu

ids Pr

oduc

t

increase

1,600

4,800

Oper

atin

g Co

st ($ / Mcf

e)

$1.00

$0.75

$0.50

$0.25

$0.00 826

$0.67

$0.48

Cash

Flow Ne

tbac

k ($/Mcfe)

2015 2016f 2017f

$1.75

$1.50

$1.25

$1.00

$0.75

$0.50

$0.25

$0.00

$2.63/MMbtu (USD, NYMEX)

$0.83

Cash Flow per Mcfe


$1.12


$1.62

95% increase

G & A Costs per Mcfe

2015 2016f 2017f

G&A

Cos

t ($ / Mcf

e)

$0.40

$0.30

$0.20

$0.10

$0.00

$0.32

$0.19

66% reduction

$0.11

*Based on strip pricing at Nov 1, 2016; see slide 11 for pricing

Best in Class Operating Cost Reductions Continuing to Drive Cash Costs Lower

$35

$30

$25

$20

$15

$10

$5

$0

$35

$30

$25

$20

$15

$10

$5

$0

Oper

atin

g Costs ($/BOE)

Oper

atin

g Costs ($/ BOE)

-56% -51% -44% -40% -34% -28% -26% -25% -23% -21% -19% -18% -16% -15% -14% -14% -10% PPY PMT PXX CR SGY AAV PWT KEL PEY BNP IKM VII RRX TOU ERF CJ PGF

Q1/15 Q2/15 Q3/15 Q4/15 Q1/16 Q2/16 Q3/16 Q4/16E Q1/17E Q2/17E Q3/17E Q4/17E

VET TET SPE BIR TOG NVA ARX BNE NBZ WCP CPG BTE PNE BXE ATH POU -9% -9% -9% -7% -7% -7% -6% -4% -1% -1% 0% 0% 7% 11% 27% 77%

10

Source: TD Securities, December 2016

Strong Cash Flow per Mcfe Positive Earnings Forecasted for 2017

Top Line Revenue $3.19/Mcfe $3.50

$3.00

$2.50

$2.00

Low Full-Cycle Costs Forecasted

to Generate Positive

Earnings in 2017 at Nov 1, 2016 Strip Pricing

$1.50

$0.55/Mcfe Net Income

$1.00

$0.50 ($0.91) Depletion / Depreciation

$0.00 ($0.16) Other Non-Cash Items

Cash Flow/Mcfe

Equals 51% of Gross Revenue/Mcfe

Royalties

($0.48)

($0.30) ($0.08) ($0.11) ($0.10)

($0.42)

Operating Expense

Transportation

Hedging Loss G&A Expense Interest Expense

Capital Lease Expense

Strip Pricing at Nov 1, 2016

2017f

Year NYMEX AECO ($USD/MMbtu) ($CAD/mcf)

2017 $3.07 $2.80 2018 $2.99 $2.87 2019 $2.94 $2.86 2020 $2.95 $2.86

11

$1.00

$0.50

$0.00

$1.50 ($0.07)

WTI ($USD/bbl)

F/X ($CAD/USD)

$49.97 1.336 $52.07 1.331 $53.32 1.327 $54.38 1.323

2017f

$1.62/Mcfe Cash Flow

*Based on strip pricing at November 1, 2016

Prudent Risk Management Financial Hedges

200

150

Station 2 Fixed Price Hedges ($/Mcf)

AECO Call Option ($/Mcf)

Unhedged

Expected A

vera

ge Nat

ural

Gas

Produ

ction

(MMcf/d)

$3.31

$3.31 $2.38

$2.22 $3.31 $3.31

$2.34 $2.74 $2.72

$3.29 $3.32 $3.37 $3.28 $3.23

450

400

350

300

Financial hedges, working together with

index physical contracts, protect cash

flow and mitigate pricing volatility

250

$2.09

$3.30

$2.09

$3.30

$2.18

$3.28

$3.31

$2.72 $3.12

100

50

0

500 AECO Fixed Price Hedges ($/Mcf)

Q4 2016e Q1 2017e Q2 2017e Q3 2017e Q4 2017e Q1 2018e Q2 2018e Q3 2018e Q4 2018e Natural Gas Production Percentage Hedged

69% 65% 63% 65% 67% 47% 33% 26% 17%

12

Note: GJ converted to Mcf at 1.15

Pricing Market Diversification

(November 1, 2016 – August 1, 2017)

13

(13%)

(14%) 18

Natu

ral Gas Produc

tion Volum

es (MMcf/d)

65% Sold on Fixed Price

Index Contracts (weighted average

price of $2.48/Mcf)

145 MMcf/d (65%)

Several Markets

Sumas Index

Spot Pricing in 35% Sold on

MMcf/d (8%)

AECO Spot

31 MMcf/d

Of the 35% of PPY’s natural gas sales

forecasted to be sold at spot pricing, 22% is sold at AECO and Sumas with less than 13% of forecasted production priced on Station 2 spot prices

Station 2 Spot

28 MMcf/d

Sales Egress Optionality Firm Transportation Supports Increasing Production Volumes

• Selling 45 MMcf/d onto AECO as at Oct 1, 2016

• Selling 18 MMcf/d at Sumas sales hub (US/Canada border) starting November 1, 2016

• 296 MMcf/d of firm transportation on Spectra’s T-North pipeline to service AltaGas Townsend Facility volumes by mid-2017

• Interim firm transportation agreements, Oct 2016 – Aug 2017, sufficient to meet commitments

• PPY volumes can be sold at either Station 2 or at Sunset Creek, which is tied directly into AECO

• Additional 130 MMcf/d firm transportation onto AECO expected in November 2017

Firm Capacity and Diversified Sales Points via AECO

or Station 2

• Additional 250 MMcf/d on T-North expected in late 2018 for a total of 570 MMcf/d of firm transportation by 2019

14

Land Position Premium Assets in the Optimum Location

All PPY Land West

of Royalty Line

OTHER

MONTNEY FAIRWAY

ROYALTY LINE

MAJOR GAS PIPELINE

ALASKA HIGHWAY

LANDS

PAINTED PONY PETROLEUM

PETRONAS

ALBERTA

BRITISH COLUMBIA

Large contiguous land base with year-round access

199 net sections (127,354 net acres)

• 2nd Largest position in northern Montney west of deep royalty line

Attractive B.C. provincial royalty structure

• $2.2 million average royalty credit per well

• Only 3% royalty during royalty credit period

Top decile average peak rates for Montney

• 111 gross wells drilled (100 operated by PPY) as at December 31, 2016

• Average 2P booking per undeveloped well of 8.8 Bcfe

High gas liquids (C3+) content

• Average 60 bbls/MMcf forecast yield at Townsend

• 1,100 Btu/scf residual heat content

15

Facilities Key Infrastructure

AltaGas Townsend Facility

• Major shallow-cut facility

• PPY has secured firm capacity for entire plant

• Phase 1 – Operating • 198 MMcf/d licensed Phase 1

capacity

• Currently flowing 150 MMcf/d of natural gas through facility

• Additional 48 MMcf/d of natural gas to be processed beginning in August 2017

• Phase 2 – October 2017 • 100 MMcf/d Phase 2 expansion

expected to be completed by October 2017 taking total processing capacity to 298 MMcf/d

16

Cypress

PPY Operated West Blair

(25 MMcf/d)

Existing AltaGas Blair Creek Plant (80 MMcf/d)

AltaGas Townsend Facility

(198 MMcf/d total current capacity; expansion to 298 MMcf/d)

Daiber

Townsend

Blair Alaska Highway

PPY Operated Daiber

(50 MMcf/d)

PPY Montney Lands

4.6 Tcfe 57%

2P Reserves

Increase in 2P Reserves

from December 31, 2014 (1)

2015 2P 7.5 times Recycle Ratio (F&D)

2015 1P 1.5 times Recycle Ratio (F&D)

2.0 Tcfe 5,009% 2015 2P Production Replacement (1) 1P Reserves

175% 3,857% Increase in 1P Reserves from December 31, 2014 (1)

2015 1P Production Replacement (1)

1P Reserve Life Index(2) 61 years $28.81 NAV Per Fully Diluted Share(3)

At December 31, 2015(1):

2015 Reserves Deep, Long-Term, Underlying Value

Increase in 2P Undeveloped Reserves

per well

2P F&D per Mcfe (including change in FDC)(4)

2P Reserve Life Index(2)

33% (to 8.8 Bcfe)

$0.16

140 years

$2.9 billion NPV10 2P Reserves (1)

$1.4 billion NPV10 Proved (1)

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

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

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

17

Canadian Natural Gas 2P Reserves As at Dec 31, 2015

33%

7.5x 10

$1.48

$1.13

$0.75 8

6

4.2 TCF

4

2

0

Cana

dian

Nat

ural

Gas

2P Reserves (Tcf)

49% Reduction in FDC/Mcfe (‘13-’15)

4th Largest 2P Natural Gas Reserves

2013 FDC/Mcfe (1)

2014 FDC/Mcfe (1)

2015 FDC/Mcfe (1)

Increase in 2P Undeveloped Reserves per well

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

2015 Cost of Supply

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

(1) FDC – Future Development Capital is capital necessary to develop those reserves deemed Undeveloped Source: TD Securities Public Companies Only; Canadian Assets 18

Reserves per Share (Mcfe

per Share)

Reserves

60 5 4.6

Assuming Enterprise Value 50 @ $10.59/sh 46.1 4

($9.00/sh equity + $2.09/sh debt)

$11.09/sh 40 $0.24 / Mcfe = ($1.44 / Boe) 2.9 46.1 Mcfe/sh

(7.7 Boe/sh) 3

29.5 30

2 19.7 20.2

1.1 0.8

Rese

rves (Tcfe)

20

11.8 13.0

1 7.4

10

4.1 2.7 2.9

0 0

488.4 MMboe

768.0 MMboe

290.3 MMboe

191.1 MMboe

136.9 MMboe

Reserves Growth Impressive and Consistent

2011 2012 2013 2014 2015

Proved Reserves Probable Reserves P+P Reserves per Share Proved Reserves per Share

• 78% Compound Annual Growth in Reserves, 2011 – 2015 • 58% Compound Annual Growth in Reserves per Share, 2011 – 2015

19

Reserves Growth / Cost Reduction Bigger and Cheaper

Reserve Growth

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

Proved Plus Probable

5.0

Finding & Development

Costs 50 Proved Reserves

46.1 $3.00 Reserves per Share (Proved)

$2.77 Reserves per Share

4.0

2013 2014

2015 (Proved Plus Probable) 40 $2.50

~130% Increase in $2.26 2P Reserves per Share -50%

2.6 $1.95

3.0 $2.00 29.5 30

Rese

rves

(Tcfe) $1.60

-57% $1.50 20.2 $1.35 $1.38

2.0 20 19.7 2.2

$1.00 90% $0.84

$0.76

1.0 1.4 7.4

Reserves (Bcfe) per YE Share 10 2.0

F&D Cost (in

cl cha

nge in FD

C) per

Mcf

e

$0.50 4.1

0.7 $0.16 0.4

~400% Increase in 1P Reserve per Share

0.0 0 $0.00 Proved Proved Plus Probable Proved Developed

Producing

20

2013 2014 2015

Total Proved Plus Probable

Reserves

4.6 Tcfe 1.7 Tcfe 2.9 Tcfe

275 140 7

Painted Pony (6.2 MMcf/d)

PPY well rates double the rates of average for

industry

Well Performance Top Performing Wells Among Montney Producers

2013-201

4 Av

erage Peak Month Ra

te (MMcf/d)

120 6

5 100

4 80

Average 3.1 MMcf/d 3 60 W

ell

Cou

nt

2 40

1 20

0 0

Source: geoSCOUT

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 Operator Rank

21

Plug and Perf Completion

Individual Stage Stimulation Envelope

~ 90-100 m Average Fracture Stage Spacing

Technology Parallel-Pair Completion Using Open Hole Ball-Drop

300-350 m Inter-well Spacing

Ball-Drop Packer

Production Increase at

No Cost Increase

Open Hole Ball-Drop Single Well

Open Hole Ball-Drop Parallel Pair Completion

• Parallel Pair Completions optimize reservoir drainage using fewer wells and less capital

• Improved recoveries combined with shallower declines help to reduce future capital necessary to maintain production which drives strong capital efficiencies 22

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

A 72% increase in 6-month cumulative production has significantly increased capital efficiencies.

10

15.5 Bcfe EUR 34% Initial Decline

2

0 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18

Production Month

Parallel Pairs Management Type Curve (15.5 Bcfe) Parallel Pairs Type Well Results (8 wells)

Single Well Ball-Drop Management Type Curve (11 Bcfe) Single Well Ball-Drop Type Well Results (9 wells)

Perf & Plug Management Type Curve (7.5 Bcfe) Perf & Plug Type Well Results (37 wells)

8

6

4

Produc

ing Rate (MMcfe/d)

*Based on strip pricing at November 1, 2016; see slide 11 for pricing; see Endnotes for list of wells which comprise management’s parallel pair type curve

Half Cycle

$13.2mm

193%

Full Cycle

$8.5mm

77%

NPV per well @ 10% (BT)

IRR

0.9 years 1.4 years Payout Period

Plan to drill 25 net wells and complete 20 net wells in 2016

Drill, Complete, Equip, Tie-In

Liquids Recovery

$4.55mm - Half Cycle $5.2mm - Full Cycle

15 bbl/MMcf (C3+)

23

2016 Development Plan & Economics Townsend – Liquids-Rich Sweet Spot

10

8

6

4

2

0

Production Month 217% 113% IRR

24

Produc

ing Rate (MMcfe/d)

*Based on strip pricing at Nov 1, 2016; see slide 10 pricing

• A 100% increase in 6-month cumulative production (1.0 Bcfe vs. 0.5 Bcfe; 9.5 Bcfe Management Type C vs. Plug & Perf Type Well) coupled with a capital cost decrease of 31%, has significantly increased capital efficiencies • Parallel Pairs type-curve results pending

9.5 Bcfe Management Type Curve – Ball Drop

9.5 Bcfe Type Well – Ball Drop (8 wells) Perf & Plug Type Well (2 wells)

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

9.5 Bcfe EUR

50% Initial 12-month Decline

Through Technology, Doubled Bcfe Recovered in First 6 Months

Drill, Complete, Equip, Tie-In

Liquids Recovery

0.8 years

$11.5mm

Half Cycle

$9.3mm

1.1 years

Full Cycle

$4.55mm – Half Cycle

60 bbl/MMcf (C3+)

NPV per well @ 10% (BT)

Payout Period

Plan to drill 11 net wells and complete 18 net wells in 2016

$5.2mm – Full Cycle

300%

Townsend 60 bbls/MMcf (9.5 Bcfe Single Well 250% Ball-Drop Type Well)

Stronger Liquids Pricing Boost Returns from Liquids-Rich

Townsend Wells

Blair-Daiber 15 bbls/MMcf (15.5 Bcfe Paired Parallel Type Well)

100%

50%

High-Rate and Liquids-Enhanced, Blair-Daiber Wells Deliver Significant Torque to Stronger

Gas Prices

0%

200%

IRR

(BT)

150%

Development Economics Price Sensitivity (Half Cycle)

$2.25 $2.50 $2.75 $3.00 $3.25

Flat NYMEX, $USD/MMbtu

*Based on WTI and F/X at strip pricing as at November 1, 2016; see slide 10 for pricing 25

Capital Expenditures 2017

Remaining 2016 Capital Spending Forecast Period

Capital

Drilling

Completions

Q4

$59 million (e)

9 net wells (e)

8 net completions (e)

2016

$213 million (e)

36 net wells (e)


2017 Capital Spending Forecast Period Capital Drilling Completions

Q1 $87 million (e) 22 net wells (e) 12 net completions (e)



Q4 $68 million (e) 13 net well (e) 13 net completions (e)

Total $319* million (e) 61 net wells (e) 61 net completions (e)

TOTAL

Townsend

35 net wells (e)


Blair – Daiber

26 net wells (e)


*2017 Capital Budget based on DC&E costs of $4.55 million per well

26

“Pony Points” Checking Off All of the Boxes

Financing In Place

Top Well Performance

Low Well Costs

Well Hedged

Rapid Growth

Lowest Royalty Framework

Processing Capacity to Support Growth

Firm Transportation

Massive Reserve Base

Focused Resource

Deep Drilling Inventory

Liquids-Rich 27

PAINTED PONY Plc„ PETROLEUM LTD.

Appendices and Disclosures

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

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

processing facilities

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

than comparable area third party marketers

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

contracts which flow through AltaGas operated facilities

• AltaGas recently announced positive FID for a propane export terminal at Ridley Island, British Columbia (FID decision announced January 3, 2017)

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

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

AltaGas is PPY’s Primary Natural Gas and NGL Marketer

AltaGas Propane Export

Terminal

Existing AltaGas PNG Mainline 10”

Potential NGL + LPG Export

Opportunity from Washington via

ALA-PetroGas at Ferndale

Planned access to both BC and Alberta Natural

Gas Sales Systems

28

Reserves Growth Per Share Growth Comparison

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

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

Source: Dundee Capital Markets 29

80%

40%

0%

-20%

-40%

-60%

60%

20%

2P Reserves per Shar

e Grow

th

2015 BOE per 1,000 Shares

2014 BOE per 1,000 Shares

2P Reserves per Share Growth (2015 over 2014)

9

8

22%

7

6

15% 13% 10% 10% 8% 7% 7%

5% 5%

-4%

1.1 1.1

0.6 0.5

2.1

1.7 1.8 2.0

1.5 1.6 1.7 1.8 1.9

3.0 2.8

3.0 3.1 -25%

3.7 3.5

-9% -10% -12%

-39% 2.0

0.7 0.9 0.1

1.2 1.2

0.5 0.6

1.0 0.7 0.3 0.4

0

1

18%

3.9

5

4

3 BOE

per 1,00

0 shar

es

2

-6%

7.7

69%

2.8

4.5 4.6

3.4

30

Capacity Proposed LNG Projects

—4.0 Bcf/d Exxon – Imperial WCC LNG

Petronas – Japex Pacific Northwest LNG

—1.4 Bcf/d Veresen Inc Jordan Cove LNG

—1.3 Bcf/d Chevron – Apache KM LNG

Pacific Oil & Gas Woodfibre LNG

Proposed West Coast LNG Projects

—0.3 Bcf/d

~18.5 Bcf/d

—3.2 Bcf/d

—3.1 Bcf/d

—2.6 Bcf/d

—2.6 Bcf/d Kitsault Energy Ltd. Kitsault Energy Ltd. (Private)

Shell – Petrochina, Mitsubishi, KOGAS LNG Canada

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

Total Filed Application Capacity (NEB)

Equity Research Sell-Side Analyst Coverage

Institution Analyst

AltaCorp Capital Patrick O’Rourke

BMO Capital Markets Joe Levesque

Canaccord Genuity Corp. Anthony Petrucci

CIBC World Markets David Popowich

Cormark Securities Inc. Garett Ursu

Credit Suisse Securities David Phung

Desjardins Capital Markets Jamie Kubik

GMP FirstEnergy Cody Kwong

IA Securities Michael Charlton

National Bank Financial Dan Payne

Paradigm Capital Inc. Ken Lin

Raymond James Jeremy McCrea

RBC Capital Markets Michael Harvey

Scotiabank Global Banking & Markets Cameron Bean

TD Securities Juan Jarrah

31

Corporate Overview

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 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

32

Endnotes

R: Reserves per share are calculated by dividing 2P reserves by shares outstanding at the end of the year. As at December 31, 2015, Painted Pony’s 2P reserves were 768 MMboe and there were 100.0 million shares outstanding. Also see “Note Regarding Reserves Disclosure” in “Advisory” section.

P: Production per million shares is calculated by dividing average production in the time period by the basic weighted average shares for the same time period. 2015 production averaged 15,604 boe/d and Painted Pony had 99.8 million weighted average shares during 2015. Amounts and estimates beyond 2015 are those of Painted Pony’s management as of the date hereof. Also see “Advisory” section.

IRR: The internal rate of return on an investment or project is the “annualized effective compounded return rate” that makes the net present value of all cash flows from a particular investment or project equal to zero.

IRR, NPV and Payout Period are all pre-tax

Type Curves Blair-Daiber: The table below is a list of all PPY Operated, parallel pair wells in the Blair-Daiber area matching the criteria below for type curve analysis, all in 94-B-16:

94-B-16 C5-K C41-F D5-K D41-F 11-F E41-F A11-F A47-K E11-F C55-F 14-F D55-F A14-F E44-C B41-F F44-C

Wells assume liquids gross-up of 15 bbl/MMcf/d, which takes the 14 Bcf management type curve to a 15.5 Bcfe management type curve .

The wells are included if they meet the following criteria: • Greater than 240 hrs of production (to avoid “flush” data, which skews the early curve too high due to frac pressure effects) • Stage numbers 18 or more, current minimum design • Drilled as Parallel Pairs, meaning the second well was fraced prior to the flowback of the original well

Public Data Analysis Methodology: • Wells “normalized” back to common start date (Month 1) • Arithmetic average of producing day rate • Months with production rate “0” excluded

33

Advisory

This presentation contains a summary of management’s assessment of results and should be read in conjunction with the Consolidated Financial Statements and related Management’s Discussion and Analysis for the quarter ended June 30, 2016, as filed on SEDAR. This presentation contains certain forward-looking statements, which include assumptions with respect to (i) drilling success; (ii) commodity prices; (iii) production; (iv) reserves; (v) future capital expenditures; (vi) future operating costs; (vii) availability of gas processing facilities; (viii) cash flow; (ix) potential markets for the Company’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 Company set forth in this presentation, including statements regarding management’s assessment of the Company’s future plans and operations, the planning and development of certain prospects, 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 Company’s control, including without limitation, risks associated with oil and gas exploration, development, exploitation, production, marketing and transportation, loss of markets, failure of foreign markets to become accessible, the impact of general economic conditions, industry conditions, volatility of commodity prices, currency fluctuations, environmental risks, competition, the lack of availability of qualified personnel or management, inability to obtain drilling rigs or other services, capital expenditure costs, including drilling, completion and facility costs, unexpected decline rates in wells, wells not performing as expected, stock market volatility, delays resulting from or inability to obtain required regulatory approvals and ability to access sufficient capital from internal and external sources, the impact of general economic conditions in Canada, the United States and overseas, industry conditions, changes in laws and regulations (including the adoption of new environmental laws and regulations) and changes in how they are interpreted and enforced, increased competition, fluctuations in foreign exchange or interest rates and market valuations of companies with respect to announced transactions and the final valuations thereof. Readers are cautioned that the foregoing list of factors is not exhaustive. The Company’s actual results, performance or achievement could differ materially from those expressed in, or implied by, these forward-looking statements and, accordingly, no assurance can be given that any of the events anticipated by the forward-looking statements will transpire or occur, or if any of them do so, what benefits the Company will derive therefrom. All subsequent forward-looking statements, whether written or oral, attributable to the Company or persons acting on its behalf are expressly qualified in their entirety by these cautionary statements. Additional information on these and other factors that could affect the Company’s operations and financial results are included in reports on file with Canadian securities regulatory authorities and may be accessed through the SEDAR website (www.sedar.com) or the Company’s website (www.paintedpony.ca), including the Company’s MD&A for the quarter ended June 30, 2016.

The forward-looking statements contained in this presentation are made as of the date on the front page and the Company assumes no obligation to update publicly or to revise any of the included forward-looking statements, whether as 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 Company believes that such information is accurate and that the sources from which it has been obtained are reliable. The Company cannot guarantee the accuracy of such information, however, and has not independently verified the assumptions on which such information is based. The Company does not assume any responsibility for the accuracy or completeness of such information.

This presentation also contains future-oriented financial information and financial outlook information (collectively, "FOFI") about prospective results of operations, future net revenue, share capital, cash flow, capital expenditures, net debt 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 Company’s ability to fund its expenditures. The Company disclaims any intention or obligation to update or revise any forward looking statements or FOFI contained in this presentation, whether as a result of new information, future events or otherwise, unless required pursuant to applicable securities law. Readers are cautioned that the forward looking statements and FOFI contained in this presentation should not be used for purposes other than for which it is disclosed herein. The forward looking statements and FOFI contained in this presentation are expressly qualified by this cautionary statement.

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

Included in this presentation are estimates of the Company's 2016-2020 cash flow which are based on various assumptions as to production levels, commodity prices and other assumptions, are provided for illustration only and are based on budgets and forecasts that have not been finalized and are subject to a variety of contingencies including prior years’ results. To the extent such estimates constitute a financial outlook, they were approved by management of the Company in November 2016 and are included to provide readers with an understanding of the Company's anticipated cash flow based on the capital expenditures and other assumptions described and readers are cautioned that the information may not be appropriate for other purposes.

34

Advisory

NOTE REGARDING RESERVES DISCLOSURE The reserves and resources estimates contained herein, including the corresponding estimates of future net revenue, are estimates only and the actual results may be greater than or less than the estimates provided herein. There is no certainty that it will be commercially viable to produce any portion of the resources.

"Reserves" are estimated remaining quantities of oil and natural gas and related substances anticipated to be recoverable from known accumulations, as of a given date, based on the analysis of drilling, geological, geophysical, and engineering data; the use of established technology; and specified economic conditions, which are generally accepted as being reasonable. Reserves are further classified according to the level of certainty associated with the estimates and may be subclassified based on development and production status.

"Total Petroleum Initially-In-Place" or "TPIIP" is that quantity of petroleum that is estimated to exist originally in naturally occurring accumulations. It includes that quantity of petroleum that is estimated, as of a given date, to be contained in known accumulations, prior to production, plus those estimated quantities in accumulations yet to be discovered (equivalent to “total resources”).

The most significant positive and negative factors with respect to the resource estimates relate to the fact that the field is currently at an evaluation/delineation stage. The Montney formation is aerially extensive in this region, however well control is limited. Both resources-in-place and productivity may be higher or lower than current estimates.

Boe may be misleading, particularly if used in isolation. A boe conversion ratio of 6 Mcf: 1 bbl is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead. Given the value ratio based on the current price of crude oil as compared to natural gas is significantly different from the energy equivalency of 6 Mcf: 1 bbl, utilizing a conversion ratio at 6 Mcf: 1 bbl may be misleading as an indication of value. Mcfe may be misleading, particularly if used in isolation. A Mcfe conversion ratio of 1 bbl: 6 Mcf is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead. Given the value ratio based on the current price of natural gas as compared to crude oil is significantly different from the energy equivalency of 1 bbl: 6 Mcf, utilizing a conversion ratio at 1 bbl: 6 Mcf may be misleading as an indication of value.

The estimated values of future net revenue disclosed in this presentation, whether calculated with or without a discount rate, do not represent fair market value. The estimates of reserves and future net revenue for individual 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. Estimates of reserves for individual properties may not reflect the same confidence level as estimates of reserves for all properties due to the effects of aggregation.

Painted Pony’s total working interest reserves, Contingent Resources and Prospective Resources are before royalties owned by others. The estimated future net revenues are stated before deducting income taxes and future estimated site restoration costs, and are reduced for estimated future abandonment costs and estimated capital for future development associated with the contingent resources. It should not be assumed that the undiscounted and discounted net present values represent the fair market value of the contingent resources and Prospective Resources.

In this presentation, information has been provided with respect to certain production information for lands and wells which is "analogous information" as defined applicable securities laws. This analogous information is derived from publicly available information sources which Painted Pony believes are predominantly independent in nature. Some of this data may not have been prepared by qualified reserves evaluators or auditors and the preparation of any estimates may not be in strict accordance with the Canadian Oil & Gas Evaluation Handbook. Regardless, estimates by engineering and geo-technical practitioners may vary and the differences may be significant. Painted Pony believes that the provision of this analogous information is relevant to Painted Pony's activities, given its acreage position and operations (either ongoing or planned) in the area in question, however, readers are cautioned that there is no certainty that any of the development on Painted Pony's properties will be successful to the extent in which operations on the lands in which the analogous historical production information is derived from were successful, or at all.

The well test results disclosed in this presentation represent short-term results, which may not necessarily be indicative of long-term well performance or ultimate hydrocarbon recovery therefrom. In this presentation, “working interest” reserves are calculated as the Company’s share of reserves, excluding royalty interest reserves and before the deduction of royalty burdens payable. The reserves report was prepared utilizing definitions as set out under National Instrument 51-101 – Standards of Disclosure for Oil and Gas Activities.

35

Documents

PAINTED PONY Investor January PETROLEUM LTD ...s2.q4cdn.com/513538771/files/doc_presentations/2017/Jan/...Presentation January 4, 2017 TSX: PPY Win / Win Relationships Long-Term Thinking