Corporate PresentationSeptember 2017

2

North Montney: Scale, Growth, Value

1. EUR 9.0 Bcf, US$50/bbl WTI, C$1.25/US$ FX, $0.30/GJ Station 2 differential, $5 MM DCET2. 312 net DSUs where one DSU = 700 acres 3. $800 MM drawn, $50 MM undrawn at Jun 30, 20174. Includes a $50 MM accordion for additional syndicate participation; $13 MM drawn at Jun 30, 20175. US dollar denominated, matures Jan 2024, 9% coupon

Material Scalable Position

• 341 net sections of Montney rights2

• 71 Hz wells drilled by YE 2017• Inventory of over 2,500 Hz locations

Strong Balance Sheet

Growth Supported by Egress

• Development plan achieves 100,000 boe/d in 5 years• Gas egress commitments growing to >390 MMcf/d• Contracts held on three major pipeline systems

High QualityAsset

• Half-cycle IRR of 75% at $2.50/GJ AECO1

• Average 9.2 Bcf EUR last 36 Hz Upper Montney wells • Recent well costs $4.2 - 4.8 MM D&C• Liquids yield of 30-50 bbl/MMcf

• $850 MM equity raised to date3 (Azimuth Capital Management, CPPIB & Warburg Pincus)

• $250 MM bank line4; US$100 MM term debt5

Infrastructure Advantage

• Owned & operated infrastructure• Operating cost <$2.50/boe through operated gas plant• Flexible pace of development

FT ST JOHN

EDMONTON

MONTNEY

BRITISH COLUMBIA

ALBERTA

10 km

Liquids-Rich Montney 218,000 net acres

100% working interest

3

Building Momentum with Scale Exiting 2017

Corporate production

• Dec 2016: 16,650 boe/d (16% liquids)

• H1 2017: 14,800 boe/d (16% liquids)

• Q4 2017 budget: 24,000 – 26,000 boe/d (17% liquids)

2017 Capital program

• $180 MM (incl. $92 MM infrastructure)

• 19 Hz wells drilled

• North Aitken Creek plant expansion to 110 MMcf/d

2016 YE reserves - independent evaluation1

• 1P = 171 MMboe (NPV10 $898 MM)

• 2P = 478 MMboe (NPV10 $2,125 MM)

• FD&A (incl. FDC)2:

• PDP: $5.86/boe

• 1P: $7.63/boe

• 2P: $5.78/boe

1. Evaluated by GLJ Petroleum Consultants2. Capital costs include the cost of the North Aitken Creek Gas Plant & land & changes

in Future Development Capital (FDC)

-

4,000

8,000

12,000

16,000

20,000

24,000

28,000Q

1

Q2

Q3

Q4

Q1

Q2

Q3

Q4

Q1

Q2

Q3

Q4

Q1

Q2

Q3

Q4

Q1

Q2

Q3

Q4

2013 2014 2015 2016 2017E

Avg

. Dai

ly P

rod

uct

ion

(b

oe

/d)

Development

Production Growth

Delineation

-

50

100

150

200

250

300

350

400

450

500

2012 2013 2014 2015 2016

Re

serv

es (

MM

bo

e)

PDP PDNP + PUD Probable

Reserve Growth

Expansion of owned infrastructure

4

Robust Economics: Low Cost, Liquids-Rich, Hot Gas

1. Inputs provided in the Appendix2. Black Swan chokes wells during initial production for operational reasons, no material impact on cumulative 365 day production3. Netback over the first year, assumes Station 2 delivery4. At $2.50/GJ AECO, US$50/bbl WTI, C$1.25/US$ FX and -$0.30/GJ Station 2 diff; liquids yield is 20 bbl C5+ and 16 bbl C3/C4

9.0 Bcf Wells Breakeven:

US$50/bbl WTI: ~$0.85/GJ AECO

Assumptions

D&C Cost ($MM, excl. $0.4 MM tie-in) $4.6

EUR (Bcf) 9.0

IP30 - Gas (MMcf/d, raw)2 7.0

IP30 - Total (boe/d) 1,300

Heat Content (MMBtu/mcf) 1,150

Liquids Yield (bbl/MMcf) 36

Royalty Drilling Credit ($ MM) $1.05

Opex & Transport ($/boe) $4.30

Revenue Enhanced by LiquidsHalf-cycle Revenue Mix at 36 bbl/MMcf4

9 Bcf Well Economic Outcome: $2.50/GJ & US$50/bbl

B-tax NPV ($MM) $7.1

B-tax IRR 75%

PI Ratio (NPV10) 1.4x

Netback ($/boe)3 $14.90

F&D ($/boe) $2.95

Recycle Ratio 4.3x

Breakeven (fixed WTI) $0.85/GJ

Payout (months) 15

Robust economics at $2.00/GJ AECO

9 Bcf type curve supported by last 36 Upper Montney Hz wells 64%

30%

6%

Gas

C5+

C3/C4

0%

20%

40%

60%

80%

100%

120%

140%

160%

$2.00/GJ AECO$40/bbl WTI

$2.50/GJ AECO$50/bbl WTI

$3.00/GJ AECO$60/bbl WTI

IRR

Black Swan Montney Half-Cycle Economics1

7.5 Bcf (8.6 Bcfe)

9.0 Bcf (10.4 Bcfe)

10.5 Bcf (12.0 Bcfe)

5

0.0

2.0

4.0

6.0

8.0

10.0

12.0

14.0

b-B

79

-G

a-A

11

-A

a-B

20

-H

b-A

22

-C

a-9

2-C

c-4

5-D

a-C

20

-H

b-1

7-H

c-B

7-H

c-A

7-H

c-7

-H

b-1

9-E

b-5

4-D

b-A

54

-D

a-5

4-D

a-A

54

-D

a-B

54

-D

a-C

54

-D

b-B

54

-D

a-D

54

-D

b-9

5-E

b-C

22

-C

b-D

22

-C

b-E

22

-C

b-F

22

-C

b-G

22

-C

a-A

92

-C

a-B

92

-C

a-C

92

-C

a-D

92

-C

a-E9

2-C

a-A

20

-E

b-B

19

-E

c-2

-C

c-A

2-C

c-B

2-C

c-C

2-C

c-D

2-C

c-E2

-C

2012 2013 2014 2015 2016 2017

EUR

(B

cf/w

ell)

Upper Montney Wells (by completion date)

EUR (Bcf) Average EUR

$0.0

$1.0

$2.0

$3.0

$4.0

$5.0

$6.0

$7.0

2014 2015 2016 2017E

D&

C C

ost

s ($

MM

/we

ll)

Drilling Cost Completion Cost Design Evolution

Ongoing operational success

• Avg EUR: 9.2 Bcf since Q3 2013 (36 wells)• Repeatable and predictable outcomes

Driving lower costs

• Continuous rig program• Ongoing optimization• Pad drilling• Frac water infrastructure • Timing of completions

Evolving wellbore design

•Testing well length, proppant loading, stage count and inter-well spacing to optimize economics:

• Sand loading increased by up to 30%

• Completed length increased by up to 50%

• Increased service costs (fracturing)

Repeatable Well Deliverability at Low Cost

Decreasing Costs on Multi-well Pads

$4.2 - $4.8 MM1

1. Range includes cost of base design $4.2 MM + $0.6 MM for cost increases on design evolution; base design includes 1,800 m lateral, 30 stages, 60 T/ frac

$6.4 MM

$4.6 MM$3.8 MM

6

Pad Operations Support Capital Efficient Growth

Upper Montney Pad Performance Tracking Type Curves

1. Pads include one Lower Montney pilot well not included in the average EUR2. Avg cost for two 2016 wells, 2015 well cost $9 MM D&C3. Based on IP 365 of 875 boe/d (half-cycle 9.0 Bcf EUR type curve, $5 MM DCET)

2-C

92-C

7-H

19-E

22-C

54-D

10 km

Upper Montney Pad Wells

Aitken Core Area

Plot Legend

Pad Year Completed

Wells/Pad

AvgD&C

($MM)

Avg EUR(Bcf)

2-C 2017 6 4.7 10.3

19-E 2015/16 3 3.72 9.0

92-C 2016 6 3.9 8.9

22-C 2015 7 4.1 10.91

54-D 2015 8 4.6 8.6

7-H 2014 5 6.4 7.31

•Best pad at 22-C paid out in under a year• Recent pads meet or exceed type curve• Drilling efficiency3

• Add 17,500 boe/d/rig annually• F&D cost<$3/boe• Capital efficiency <$6,000/boe/d

0

1,000

2,000

3,000

4,000

5,000

6,000

7,000

8,000

9,000

10,000

0 60 120 180 240 300 360 420 480

Mcf

/d

Normalized Days

10.5 Bcf9.0 Bcf7.5 Bcf

Type Curves

Core area delineated with high rate pads

7

Owned and Operated Infrastructure: Flexible Pace of Growth

North Aitken Creek Gas Plant

110 MMcf/d capacity

10” sales gas line; connects to Enbridge T-North system

50 MMcf/d compression & dehy, volumes

flow to McMahon for

processing

6”

6”

6”

10”

10”

Gathering trunk-lines built H1/16

10”

8”

10 km

Existing gathering trunk-lines

100% Owned & operated infrastructure

Plant 1: North Aitken Creek Gas Plant

• Phase 1: 50 MMcf/d

• Phase 2: 60 MMcf/d

• Liquids recoveries capable of ~40 bbl/MMcf (>50% C5+)

Plant 2: 198 MMcf/d facility

• Engineering in progress

• Long lead equipment included in 2017 budget

• Phase A on-stream timing to match pipeline expansions

Infrastructure investment

• At 2016 YE: $220 MM

• 2017 Budget: $92 MM

North Aitken Plant 1

110 MMcf/d raw capacity

Future site for Plant 2

Pipeline infrastructure in place to support growth• 35 km of gathering lines

• 20 km of raw gas lines (to third party facilities)

• 10 km sales gas line (gas plant to T-North)

8

0

10

20

30

40

50

60

70

80

90

100

0

20

40

60

80

100

120

Jan/16 Apr/16 Jul/16 Oct/16 Jan/17 Apr/17 Jul/17

Liq

uid

s Y

ield

(b

bl/

MM

cf)

Gas

Pro

du

ctio

n (

MM

cf/d

)

North Aitken Creek Gas Plant Production

Inlet Gas (MMcf/d) Inlet Capacity (MMcf/d)C5+ Yield (bbl/MMcf) C3/C4 Yield (bbl/MMcf)

$14.70

$6.73

$1.19

$2.70

$2.00 $1.16

$0.00

$5.00

$10.00

$15.00

$20.00

$25.00

Costs Revenues

$/b

oe

North Aitken Gas Plant H1 2017 Operating Netback

Royalty

Transportation

Operating Cost

C3/C4 Revenue

C5+ Revenue

Gas Revenue

Owned and Operated Infrastructure: Superior Netback

Current capacity: 85 MMcf/d (16,000 boe/d)

• Phase 1 above name plate capacity

• Initial condensate/C5+ up to 40 bbl/MMcf

• Stabilizes at >20 bbl/MMcf after one year

• Plant optimized to maximize netbacks:

• C3/C4 yield: 10-20 bbl/MMcf

• Gas heat content: 1,150-1,170 MMbtu/mcf

Operating costs to trend <$2.50/boe in 2017

• YTD costs reflect turnaround and expansion

• Plant operating netbacks >$16.50/boe in H1 2017

• Produced water recycledField netback $16.76/boe

Production shut-in to facilitate offsetting completions of new pads

Downtime for expansion and turnaround

9

$13.13

$5.86

$1.20 $0.19 $1.57

$4.26

$2.56 $1.22 $1.10 $1.96

$0.00

$5.00

$10.00

$15.00

$20.00

$25.00

Costs Revenues

2017E

$/b

oe

2017E Revenues vs. CostsInterest

Royalty

G&A

Transportation

Operating Cost

Hedging

Processing Income

C3/C4 Revenue

C5+ Revenue

Gas Revenue

Capital Program Drives Transition to Low Cost Structure

Cash flow netback $10.86/boe1

2017 YTD production at record rates

• Stable production of 16,700 boe/d in Q1

• North Aitken Phase 2 commissioned in June, ahead of schedule

• Annual maintenance period was utilized to commission Phase 2 and to conduct completions that offset existing pads

Production outlook

• Production to exceed 25,000 boe/d in Q4 with installation of final inlet compressor

Cost structure

• Operating and corporate costs per boe trending lower with increased volumes through Black Swan facilities

1. Based on annual production of ~18,000 boe/d at $2.29/GJ AECO, -$0.43/GJ Station 2 to AECO differential, US$50/bbl WTI and $1.30 C$/US$

0

5,000

10,000

15,000

20,000

25,000

30,000

Jan-16 Apr-16 Jul-16 Oct-16 Jan-17 Apr-17 Jul-17 Oct-17 Jan-18

Dai

ly P

rod

uct

ion

(b

oe

/d)

Black Swan Production

Actuals (Gas) Actuals (Liquids) Base Decline Q3 2017 Completions

Forecast

on-stream

2017 completions

Enbridge’s McMahon turnaround completed

North Aitken Plant & Enbridge McMahon turn arounds

10

2017 Outlook: Growth to 25,000 boe/d With Pad Drilling

42-D Pad(8 wells)

2-C Pad(6 wells)

72-C Pad(6 wells)

32-C Pad(6 wells)

North Aitken Plant

10 km

21%

22%

5%

48%

4%

2017 Capital Program

Drilling

Completions

Wellhead tie-in

Gathering & facilities

Other

Capital program

• 2017 budget: $180 MM

• 19 Hz wells drilled, 16 completed, 16 tied in

• Test well length, proppant loading and stage count coupled with inter-well spacing to lower cost while improving recovery

• North Aitken Creek expansion to 110 MMcf/d

• Long lead items for 198 MMcf/d Plant 2

Funding1

• 2017E cash flow from operations: $75 - $80 MM

• 2017E year-end net debt: $190 - $ 195 MM

• Expect to draw less than $60 MM of existing $250 MM bank facility

Corporate production

• 2017E: 17,500 – 18,500 boe/d

• Exit Production: 24,000 – 26,000 boe/d (17% liquids)

-

5,000

10,000

15,000

20,000

25,000

30,000

Q4 2016 Q4 2017E

Pro

du

ctio

n (

bo

e/d

)

Over 60% Production Growth Y/Y

1. Based on annual production of ~18,000 boe/d at $2.29/GJ AECO, -$0.43/GJ Station 2 to AECO differential, US$50/bbl WTI and $1.30 C$/US$

11

Free cash flow positive at low prices

•At $2.50/GJ AECO & $50/bbl WTI

• Only 50% of cash flow is required to maintain production

• Able to maintain production at low prices

•Reflects strong fundamentals:

• F&D cost <$3/boe

• Capital efficiency <$6,000/boe/d

• Average 9.2 Bcf over last 36 wells

Flexibility to modify pace of growth

• Positioned for growth at favorable prices

• Operated facilities provides flexibility to manage pace

Stable Base Production: Minimal Maintenance Capital Required

1. Notes:• Assumes 35% base decline; $6,000/boe/d rig efficiency, $5MM/year miscellaneous field capital• Prior to hedging gains/losses; Assumes $0.30/GJ Station 2 Differential • The ratio between maintenance capital and free cash flow will remain the same as productions

grows

$0

$20

$40

$60

$80

$100

$120

$140

$160

$180

$2.00/GJ AECO $2.50/GJ AECO $3.00/GJ AECO

US$40/bbl WTI US$50/bbl WTI US$60/bbl WTI

$M

M

Free Cash Flow Generation at 26,000 boe/d1

Maintenance Capital Free Cash Flow Total Cash Flow

12

Aitken Area Capable of Delivering & Sustaining >100,000 boe/d

10 km

Aitken Core Development Area

Development plan1 uses <20% of inventory•Upper Montney has been delineated across the Aitken

core development area; 430 Hz locations remaining

•200 Hz wells over the next 5 years

•230 additional Upper Montney Hz locations maintain 100,000 boe/d for an additional eight years

•Remaining acreage & landing zones have potential to• Increase peak production, or• Extend production plateau

Capital efficient asset provides robust growth

• Single continuous rig program provides up to 20 wells per year

• 17,500 boe/d/rig annually2

• At $2.50/GJ AECO and $50/bbl WTI, can fund growth to 100,000 boe/d with cash flow and debt

Aitken core development delineated; upside on

northern acreage

1. Drilling plans are subject to annual review and may be modified based on factors including: commodity prices, facility access and regulatory constraints

2. Based on IP 365 of 875 boe/d (half-cycle 9.0 Bcf EUR type curve, $5 MM DCET)

13

0

50

100

150

200

250

300

350

400

Sep

Dec

Mar

Jun

Sep

Dec

Mar

Jun

Sep

Dec

Mar

Jun

Sep

Dec

Mar

Jun

Sep

Dec

2017 2018E 2019E 2020E 2021EG

as (

MM

cf/d

)

Planned Plant Capacity vs. Egress Commitments

EnbridgeSpruce RidgeEnbridgeExistingTCPL NorthMontneyAlliance

Plant 2A

Plant 2B

Existing PlantCapacity

Egress Commitments Provide Transformational Growth

Full cycle economics underpinned by owned & operated infrastructure

• New processing units will be built in 100 MMcf/d (19,000 boe/d) increments

• Plant construction will be timed to align with pipeline expansion

McMahon Gas Plant

Sunset

T-South to Huntington/Sumas

Station 2

Aitken Creek Gas Storage

NGTL to AECO

North Aitken Gas Plant

BR

ITIS

H C

OLU

MB

IA

ALB

ERTA

25 km

1. NGTL is part of the TransCanada pipeline system2. North Montney Mainline & Enbridge Spruce Ridge projects are subject to regulatory approval3. Includes Black Swan owned & operated processing & existing McMahon commitments (raw capacity)4. Unutilized tolls: $0.8 MM/month post Plant 2A; $0.4MM/month post Plant 2B; $1.8 MM/month with no new processing capacity

Firm service egress commitments grow to 392 MMcf/d

• Egress on all three Canadian gas transmission systems2

• Greater than 2/3 of production to AECO in 2019

Option to accelerate

14

Source Water Secured for Development Plan

Beatton River water license

• License supports peak drilling rate of 100+ Hz wells/year

• Underpins growth to 100,000 boe/d

• Permanent intake and storage in place

• License valid until Dec 31, 20211

Responsible management & recycling • Over 1.5 MMbbl of fresh water storage capacity

constructed

• Produced water is recovered and recycled

• Produced water handling infrastructure is temporary by design to allow flexibility of operation and optimization of capital

Water License Intake 1

Water Pump Station

b-54-D Fresh Water Pit65,825 m³

c-7-H Fresh Water Pit 60,300 m³ capacity

Water pump station 1. With renewal provisions

b-11-A Fresh Water Pit44,900 m³

10 km

d-42-D Fresh Water Pit65,000 m³

15

Risk Management & Pricing

-

10,000

20,000

30,000

40,000

50,000

60,000

70,000

Aug - Dec 2017 2018 2019

He

dge

d V

olu

me

s (G

J/d

)

Annual Hedging & Average Contract Pricing

Station 2 Diff ($/GJ) AECO Swaps ($/GJ)

AECO Collars ($/GJ) AECO Puts ($/GJ)

Chicago Swaps (C$/MMBtu)

0

100

200

300

400

500

600

700

800

900

Aug - Dec 2017 2018 2019

C4

& C

5+

Pro

du

ctio

n (

bo

e/d

)

Liquids Hedging & Average Contract Pricing

Swaps (C$ WTI) Collars (C$ WTI)

• Black Swan utilizes financial and physical contracts to manage price volatility

• Hedge positions can be taken to cover production up to three years out with positons layered in over time

Gas volumes are delivered primarily to Station 2 Liquids (C4 & C5+) represent >30% of revenue & priced vs. WTI

$2.72

-$0.52

$2.85 x

$3.21$2.60 $4.17

-$0.49

$2.72

$2.56

-$0.37

$2.81

$65.86

$57.51 x

$69.72

$71.78

$70.98

Note: Put prices are shown net of premiums and Chicago prices are shown prior to transportation costs on Alliance

$55.00 x

$67.25$55.00 x

$68.00

53%

29%

3%1%

11%

15%

32%

56%

0%

20%

40%

60%

80%

100%

Aug - Dec 2017 2018

% o

f C

orp

ora

te P

rod

uct

ion

2017/2018 Gas Pricing Portfolio

Unhedged Station 2

Unhedged AECO

Unhedged Chicago

Hedged Chicago

Hedged AECO35%

13%

65%

87%

0%

20%

40%

60%

80%

100%

Aug - Dec 2017 2018

% o

f C

orp

ora

te P

rod

uct

ion

2017/2018 Liquids (C4 & C5+) Pricing Portfolio

Unhedged

Hedged

16

0

100

200

300

400

500

600

700

800

Pro

gre

ss

Bla

ck S

wan

CN

Q

Sagu

aro

TOU

Po

lar

Star CR

AR

X

PP

Y

SRX

SU

ECA

CK

E

Can

bri

am RD

S

LXE

Ad

uro

TOD

D/P

OU

CO

P

KEL

PG

F

MU

R

Ne

t D

SUs2

Over-pressured; repeatable deliverability•Highly over-pressured reservoir 13-16 kPa/m

Liquids-rich•Total liquids of 30-50 bbl/MMcf1 (>50% C5+)

Low cost •Shallow target, surface access and drilling characteristics

Scalable• Large contiguous position

Liquids-rich gas

Dominant Position in Over-Pressured, Liquids-Rich Fairway

Black Swan holds the second largest liquids-rich position in

the NEBC Montney fairway

Liquids Rich Montney Rights

Dry gas Oil

Upper Montney Oil Window

Normally Pressured

Upper Montney Dry Gas

Alb

erta

B.C

.

Caribou

Umbach

Town

AltaresSeptimus

Groundbirch

Swan

Parkland

Aitken

Beg

JedneyLaprise

Montney Hz post 2013

Legend

Montney Hz

Black Swan land

Liquids-rich gas window

Dry gas window

Oil window (>75 bbl/MMcf)

Montney TVD contour1600m

25 km

Upper Montney Over-Pressured

Liquids-Rich Fairway

17

$0.0

$2.0

$4.0

$6.0

$8.0

$10.0

$12.0

D&

C C

ost

$M

M

Drilling & Completion Cost (2016)

0%

10%

20%

30%

40%

50%

60%

70%

80%

90%

100%

Gas

We

igh

tin

g

Gas Weighting (2016)

$0.00

$2.00

$4.00

$6.00

$8.00

$10.00

$12.00

20

17

E $

/bo

e

Operating Cost (2017E)

0.0

2.0

4.0

6.0

8.0

10.0

12.0

EUR

(B

cf)

EUR2 – Wells Drilled in Last Three Years

Differentiation: Performance on Multiple Factors vs. Peers1

Well performance

Leading capital efficiencies

Infrastructure advantage

Liquids contribution

Black Swan Full Cycle

Forward Economics3

$/boe

Revenue 20.75

Royalty 1.35

Opex + transport 5.10

G&A + interest 2.45

Cash Netback 11.85

Half cycle F&D (2.95)

Infrastructure (2.55)

Full cycle F&D 5.50

Profit 6.35

Recycle ratio 2.2x

1. Peer group includes: AAV, ARX, BIR, Canbriam, CR, KEL, NVA, PPY, Saguaro, SRX, TOU, VII2. Internal estimates, Montney gas & liquids rich wells 3. Inputs based on $2.50/GJ AECO, $50/bbl WTI, 9 Bcf type curve and expected five year growth profile

BSE8.3

BSE3.8

BSE4.11

BSE84%

Source: Internal estimates & company reports

Includes three Lower Montney wells BSE Plant (excludes McMahon production)

18

Strategic Focus: Scalable, Low Cost Growth

Current Activity

• Pad development: one-rig Montney program• North Aitken Gas Plant expansion to 110 MMcf/d• Engineering and long lead items for 198 MMcf/d Plant 2

One to Three Year Window

• Accelerate development plan with additional rigs• Commission Plant 2• Advance planning for additional processing capacity

Ongoing

• Strong balance sheet; disciplined capital management• Low cost operations• Technical innovation and continuous improvement

19

Appendix:Corporate & Financial Summary

20

Black Swan Energy Executive Team

David Maddison, P.Eng.David is President, CEO and founder of Black Swan Energy. He has over 37 years of industry experience focused on conventional and resource plays in Western Canada. Prior to Black Swan, he was with Talisman Energy where he managed multi-disciplinary teams in the WCSB, with production of 100,000 boe/d and annual capital budgets of $1 billion.

Marc Mereau, P.Eng.Marc is Chief Operating Officer and a co-founder of Black Swan Energy. He has over 36 years of experience in the oil and gas industry, both domestically and internationally. Prior to Black Swan, Marc worked at Talisman Energy, where he held progressively larger roles including Senior Vice President of Western Operations for North America.

Michael Wilhelm, B.Comm., CPA, CGAMike is Vice President, Finance and CFO and a co-founder of Black Swan. He has over 30 years experience in the oil and gas industry, with an extensive background in both private and public financings in Canadian and U.S. markets. Mike was involved as a founder and in the ongoing funding of Equatorial Energy and Espoir Exploration. He was also involved with the IPO of Resolute Energy Inc. through the RTO of Equatorial Energy Inc.

Bruce Thornhill, P.GeoBruce is Vice President, Exploration of Black Swan Energy. He has over 35 years of experience in the energy industry focused on conventional and resource play exploration and development throughout Western Canada, primarily in Deep Basin areas. Prior to joining Black Swan, he was a member of the senior management team at TAQA North, first as VP of Exploration and later as VP of the North Asset managing an annual capital budget of $200MM.

Bryan Lang, P.Eng.Bryan is Vice President, Operations of Black Swan Energy. He has over 27 years of experience in the energy industry focused on Western Canadian operations. He started his career at Chevron Canada and at growth oriented operators Northrock Resources and Peyto Exploration. He played a lead role in the development of horizontal multistage resource plays, and has assembled highly efficient teams focused on safe, low cost operations.

Leanne Juneau, B.Comm.Leanne is Vice President, Land and co-founder of Black Swan. She has over 20 years experience negotiating and executing exploration and development agreements and strategic corporate and asset acquisitions and dispositions within Western Canada totaling over $500 million. She has previously held positions at Redcliffe Exploration, Talisman Energy and Northrock Resources.

Diane Shirra, B.Eng., MBA, P.Eng.Diane is Vice President, Business Development of Black Swan. She has over 33 years of experience in the energy industry focused on exploitation and development of both conventional and resource plays throughout Western Canada. Most recently she was VP Montney Gas Development and VP Reserves and Strategic Projects at Pengrowth Energy Corporation.

Christine Ezinga, B.Comm., CFAChristine is Vice President of Strategy & Planning at Black Swan Energy. She has over 16 years of diverse capital markets experience in finance, investor relations and corporate development with direct involvement in over $9 billion of executed M&A deals. Prior to joining Black Swan, she was Team Lead – Finance, Business Development at Sinopec Canada, following the successful sale of Daylight Energy to Sinopec.

21

Black Swan Energy Board of Directors

David B. Krieger David is a member of the Warburg Pincus Executive Management team, having joined Warburg in 2000, and focuses on energy investments. Previously, he worked at McKinsey & Company. Mr. Krieger is a Director of Kosmos Energy, MainSail Energy, MEG Energy, Osum Oil Sands, Rubicon Oilfield International, Sheridan Production, Trident Energy and Velvet Energy. Mr. Krieger received a B.S. in economics summa cum laude from the Wharton, an M.S. with high honors from the Georgia Institute of Technology and an M.B.A. with distinction from Harvard Business School.

Dr. James BuckeeIn September 1991 Jim was appointed President and Chief Operating Officer for BP Canada Inc. and in May 1993 he was appointed President and Chief Executive Officer of Talisman Energy Inc. (formerly BP Canada). When Jim retired, in October 2007, Talisman was producing over 500,000 boe/d. He also serves on the boards of Magma Global and M-Flow and sits on the advisory Board of Azimuth Capital Management. Jim holds a BSc Honours in Physics from the University of Western Australia and in 1970 he received his PhD in Astrophysics at Oxford University.

Jackie Sheppard, Lead DirectorJackie was the Executive Vice-President, Corporate and Legal and Corporate Secretary for Talisman Energy Inc. She served as Secretary to the Board responsible for Corporate Projects and Acquisitions, Communications and Investor Relations. She currently serves on the Boards of Cairn Energy, Emera Inc. and Seven Generations

Robert MellemaRobert has been with the Canada Pension Plan Investment Board (CPPIB) since 2008 and focuses on Natural Resources investments. Prior to joining CPPIB, Mr. Mellema worked at UBS on the Canadian M & A team. Mr. Mellema serves as a Director on the boards of Livingston International Inc. and Wolf Midstream and has previously been involved in CPPIB’s investments in Teine Energy and Seven Generations Energy. Mr. Mellema holds a MBA from the Wharton School at the University of Pennsylvania and a Bachelor of Commerce degree from Queen’s University.

Roy Ben-DorRoy joined Warburg Pincus in 2011 and previously worked at McKinsey & Company in New York. He is also a director of MainSail Energy and Zenith Energy and works with MEG Energy, Navitas Midstream and Osum Oil & Sands. He received his BA cum laude in psychology and economics with Distinction from Duke University, a J.D. magna cum laude from Harvard Law School and a MBA with high distinction from Harvard Business School.

Jim NieuwenburgJim is an Operating Partner at Azimuth Capital Management. He has over 35 years of experience in the energy sector and over 20 years of executive management and corporate governance experience. Previously, he has held positions at Petromet Resources (CEO), Norcen Energy (Vice President) and Amoco Canada. Jim also serves as a Director on the boards of Corex Resources, Monolith Materials, Recovery Energy Services and Rifco Inc.

Dave PearceDave is Deputy Managing Partner with Azimuth Capital Management. During his 36 years in the energy sector, Mr. Pearce has worked in a variety of technical and executive roles in Exploration, Production and Corporate Development as well as an Independent Director in Canada and internationally. Mr. Pearce was President and CEO of Northrock Resources, an intermediate Canadian E&P company. Currently, Mr. Pearce is also a Director of TimberRock Energy, Altex Energy Ltd., Kaisen Energy, Kaden Energy, Entrada Resources and Raging River Exploration.

David Maddison, P.Eng.David is President, CEO and founder of Black Swan Energy. He has over 37 years of industry experience focused on conventional and resource plays in Western Canada. Prior to Black Swan, he was with Talisman Energy where he managed multi-disciplinary teams in the WCSB, with production of 100,000 boe/d and annual capital budgets of $1 billion.

22

Historical Financial Summary

1. Preliminary values, subject to Audit Committee approval2. NOI as presented does not include realized hedging gains/(losses)3. EBITDA calculated as NOI + processing income – G&A

2017 2016 2016 2015 2015 2014 2014

Q21 Q1 Full Year Q4 Q3 Q2 Q1 Full Year Q4 Q3 Q2 Q1 Full Year Q4 Q3 Q2 Q1

Production

Oil (bbl/d) - - 16 - - - 65 79 54 64 82 116 17 69 - - -

Gas (mcf/d) 66,194 85,832 67,151 74,626 75,484 71,376 46,944 23,538 26,513 24,318 19,431 23,853 18,220 22,410 21,098 17,185 12,044

NGL (bbl/d) 1,868 2,427 2,099 2,254 2,506 2,399 1,232 614 875 539 519 521 442 496 483 448 339

Total (boe/d) 12,900 16,732 13,307 14,692 15,087 14,295 9,121 4,616 5,348 4,656 3,840 4,612 3,496 4,300 3,999 3,312 2,346

Financial ($ 000)

Net Operating Income2 14,241 22,639 50,484 20,154 16,506 10,188 3,636 13,098 3,082 3,272 3,945 2,799 24,794 5,169 7,024 6,995 5,606

EBITDA3 13,074 20,722 47,513 15,529 16,104 11,452 4,428 6,819 1,571 1,559 2,558 1,131 17,417 2,480 5,580 5,216 4,141

Cash Flow 9,705 17,841 43,225 14,503 15,138 9,518 4,066 4,881 1,103 1,176 1,598 1,004 17,014 2,390 5,553 5,015 4,056

Capex (incl. A&D) 54,539 49,377 84,453 28,432 23,499 (2,209) 34,731 402,684 58,667 79,415 222,931 41,671 120,530 47,999 29,554 17,417 25,560

Capital Structure ($ 000)

Working Capital Deficit (Surplus) 23,916 (8,140) 11,507 11,255 5,875 612 16,981 46,854 46,854 41,707 (7,196) 32,116 16,449 16,449 840 (1,981) (14,482)

Bank Debt 13,091 - 76,555 76,555 68,258 65,180 60,538 - - 555 50,000 25,000 - - - - -

Term Notes 125,645 128,867 - - - - - - - - - - - - - - -

Total Net Debt 162,916 120,727 88,062 87,810 74,133 65,792 77,519 46,854 46,854 41,262 42,804 57,116 16,449 16,449 840 (1,981) (14,482)

Total Credit Facility 200,000 200,000 200,000 200,000 140,000 140,000 130,000 130,000 130,000 80,000 70,000 70,000 40,000 40,000 24,000 24,000 12,000

Netback Summary ($/boe)

Net Revenue 22.13 23.07 17.97 22.65 18.83 14.97 13.60 18.82 16.26 18.19 21.77 20.02 34.69 26.39 33.43 40.01 44.88

Hedging Gain (Loss) 0.27 (0.20) 0.87 (1.28) 0.44 2.46 2.60 0.33 0.60 (0.04) 0.60 0.15 - - - - -

Royalties (1.02) (1.26) (0.94) (1.44) (1.13) (0.46) (0.57) (0.99) (0.73) (0.76) (0.95) (1.57) (3.67) (3.67) (3.33) (3.77) (4.12)

Opex (5.74) (4.39) (4.56) (4.01) (3.53) (4.49) (6.34) (9.07) (7.49) (9.24) (8.80) (10.99) (10.77) (8.82) (10.13) (12.24) (13.44)

Transportation (3.23) (2.34) (2.10) (2.29) (2.28) (2.19) (2.31) (0.98) (1.77) (0.55) (0.73) (0.72) (0.82) (0.83) (0.88) (0.79) (0.77)

Operating Netback 12.40 14.83 11.24 13.63 12.34 10.29 6.98 8.11 6.87 7.60 11.89 6.89 19.43 13.07 19.09 23.21 26.55

General & Administrative (1.45) (1.27) (1.76) (2.33) (1.12) (1.68) (2.01) (4.52) (5.28) (3.95) (4.57) (4.17) (5.78) (6.80) (3.92) (5.90) (6.94)

Processing Income 0.19 0.20 0.27 0.19 0.38 0.19 0.37 0.47 1.61 - - - - - - - -

Interest/Other Expense (2.87) (1.91) (0.87) (0.74) (0.70) (1.48) (0.44) (1.16) (0.96) (0.90) (2.75) (0.30) (0.32) (0.23) (0.08) (0.68) (0.40)

Cash Flow From Operations 8.27 11.85 8.88 10.73 10.91 7.32 4.90 2.90 2.24 2.75 4.57 2.42 13.33 6.04 15.09 16.64 19.21

23

Appendix:Half-cycle Input Assumptions

24

Type Curve Assumptions

1. Economics assume Black Swan owned infrastructure; FX C/US$ of $1.30, $1.25 & $1.20 at US$40/bbl, US$50/bbl & US$60/bbl respectively; Station 2 differential = $0.32/mcf

2. Economics include equip & tie-in costs of $0.4 MM/well for total well costs of $5 MM

3. Black Swan pays BC Crown royalties calculated on a sliding scale for gas based on price and production rate & fixed percentage of revenue for liquids

4. Pricing relative to C$WTI: C5+: 91%, C4: 41%, C3: 10% at US$50/bbl oil (realizations include price offsets; trucking of $4.00/bbl included in opex & transportation)

5. Opex & transportation represent the average cost during the first 12-months

25

Appendix:Drilling, Completions & Well Results

26

0

200

400

600

800

1,000

1,200

1,400

1,600

1,800

2,000

2,200

2,400

2,600

2,800

3,000

3,200

3,400

3,600

3,800

4,000

4,200

4,400

4,600

0 2 4 6 8 10 12 14 16 18 20

De

pth

(m

MD

)

Total Days

Total Time vs. Depth

2015/16 Pad Wells

2017 Pad Wells

2017 Best Pad Well

Drilling Improvements Early in Development

• Black Swan has established a highly effective drilling program as a result of continuous operations

• One new high horsepower telescopic double top drive rig commissioned in Q3 2013

• Use of preset rig minimizes costs between surface hole and monobore

• ‘Tapered’ monobore well design reduces overall well costs, improves frac hydraulics

• Continuous improvements with drilling fluids, bit and BHA design, rig technology

• On average wells are drilled and cased in under two weeks; 20+ wells/rig/year

• Drilling cost per meter reduced 12% in 2017 with improvements in drilling efficiency and longer laterals

Build section (turn to Hz)

Change to slim Hz drilling assembly

Set packers, cement, rig out

Preset Rig

PadRig

Move pad rig, install BOP

Preset surface, skid rig

27

Completions: Optimization of Design

4,600

5,600

6,600

7,600

2012 2013 2014 2015 2016 2017

1,400

1,600

1,800

2,000

2,200

2,400

2,600

fee

t

me

tre

s

Completed Well Length

330

430

530

630

730

830

930

2012 2013 2014 2015 2016 2017

0.5

0.7

0.9

1.1

1.3

1.5

lbs/

ft

ton

ne

/m

Proppant Concentration

0

100

200

300

400

500

600

700

2012 2013 2014 2015 2016 2017

020406080

100120140160180200220

fee

t

me

tre

s

Stage Spacing

Current Completion Design

Open hole ball drop• 2,200 m lateral, 34 stages, single port entry• 65 m port spacing• Proppant: 90 tonne/stage, 3,000 tonne/well, 1.33 tonne/m loading• 13,000 m3 recycled slickwater blend

Pad design modifications provide• Optimized landing interval for frac initiation, geometric completion design• Multiple wells with modified zipper frac• Complementary inter-well stage overlap with maximum interference between

wells/stages to enhance stimulated reservoir volume

Early move to short stages, optimizing well length and sand loading in development• 2012/13 – Perf-plug, long stage length, 8 stages x3 perfs/stage, 0.7 t/m• 2014/15 – Open hole, short stage length, 20 stages, 1.0 t/m• 2016/17 – Reduced stage length, increased lateral length, 33 stages,

1.33 t/m• From early development to current design, +33% increase in length, 70%

reduction in stage spacing and 80% increase in sand loading resulting in increasing EUR per well and high recovery factor

Completion Design Evolution

Optimizing Recovery Per DSU• Extended reach wells to reduce capital• Tighter stage spacing (65m vs 90m)• Increased sand intensity with wider inter-well spacing• Fluid additive technology, diversion techniques• Unlimited stage fracturing systems

28

Upper Montney Multi-Well Pad Production Summary

• Black Swan utilizes downhole chokes on all Hz wells for operational purposes

• Data presented is based on actual daily production which has been normalized to adjust for downtime

Note: Gas rates shown are raw

Internal UWI Completion Montney IP30 IP90 IP365Cum to Jun/17 EUR

Reference (Year) Target (MMcf/d) (MMcf/d) (MMcf/d) (Bcf) (Bcf)

9 Bcf Type Curve (unrestricted) 7,000 6,100 4,330 9.0

9 Bcf Type Curve (choked) 4,400 4,400 3,980 9.0

2-C Well Pad

c-E2-C 200/a-091-K 094-A-13/00 2017 Upper 6,641 NA NA 0.1 10.1

c-D2-C 200/b-100-J 094-A-13/00 2017 Upper 5,815 NA NA 0.0 10.8

c-C2-C 200/a-100-J 094-A-13/00 2017 Upper NA NA NA 0.0 10.6

c-B2-C 200/c-025-C 094-H-04/00 2017 Upper NA NA NA 0.0 9.2

c-A2-C 200/b-035-C 094-H-04/00 2017 Upper NA NA NA 0.0 10.3

c-2-C 200/a-035-C 094-H-04/00 2017 Upper NA NA NA 0.0 11.0

19-E Well Pad

b-B19-E 200/b-097-D 094-H-04/00 2016 Upper 3,240 4,444 NA 0.5 9.0

a-20-E 200/c-088-D 094-H-04/00 2016 Upper 5,000 4,448 NA 0.7 7.5

b-19-E 200/b-098-D 094-H-04/02 2015 Upper 5,701 5,129 4,617 2.3 10.5

92-C Well Pad

a-B92-C 200/c-004-F 094-H-04/00 2016 Upper 5,917 5,577 NA 0.8 10.0

a-A92-C 200/a-014-F 094-H-04/00 2016 Upper 6,126 5,615 NA 0.7 10.0

a-E92-C 200/b-080-B 094-H-04/00 2016 Upper 4,847 4,309 NA 0.5 7.5

a-D92-C 200/a-080-B 094-H-04/00 2016 Upper 4,833 4,317 NA 0.9 8.0

a-C92-C 200/d-080-B 094-H-04/00 2016 Upper 3,774 3,519 NA 0.4 7.5

a-92-C 200/d-004-F 094-H-04/02 2013 Upper 5,886 5,951 NA 1.2 10.5

22-C Well Pad

b-G22-C 202/b-010-B 094-H-04/00 2015 Upper 7,343 6,450 NA 1.6 11.0

b-F22-C 200/d-010-B 094-H-04/00 2015 Upper 5,790 6,375 5,217 2.1 12.0

b-E22-C 202/c-034-C 094-H-04/00 2015 Upper 7,886 7,001 NA 1.5 11.0

b-D22-C 200/c-034-C 094-H-04/00 2015 Upper 6,656 6,454 4,995 1.7 11.0

b-C22-C 200/a-044-C 094-H-04/00 2015 Upper 6,522 5,783 NA 1.4 10.5

b-A22-C 200/c-010-B 094-H-04/02 2013 Upper 6,521 5,900 4,655 1.6 10.0

54-D Well Pad

a-D54-D 200/a-075-D 094-H-04/00 2015 Upper 4,428 4,431 3,697 1.7 9.0

b-B54-D 200/b-075-D 094-H-04/00 2015 Upper 4,659 4,587 3,367 1.5 8.0

a-C54-D 202/d-066-D 094-H-04/00 2015 Upper 4,520 4,271 3,454 1.6 8.0

a-B54-D 200/d-066-D 094-H-04/00 2015 Upper 5,065 4,602 3,336 1.5 7.5

a-A54-D 202/a-032-D 094-H-04/00 2015 Upper 6,893 6,042 4,695 2.0 9.0

a-54-D 200/a-032-D 094-H-04/00 2015 Upper 3,913 4,201 3,739 1.5 8.5

b-A54-D 200/b-032-D 094-H-04/00 2015 Upper 5,368 4,949 3,923 1.5 9.0

b-54-D 200/a-033-D 094-H-04/00 2015 Upper 5,284 5,080 3,920 1.6 9.0

7-H Well Pad

c-B7-H 200/b-095-A 094-G-01/02 2014 Upper 4,233 2,922 3,137 1.8 7.2

c-A7-H 202/a-096-A 094-G-01/00 2014 Upper 4,870 4,274 2,738 1.6 6.0

c-7-H 200/b-096-A 094-G-01/00 2014 Upper 7,506 4,559 3,171 1.7 6.0

b-17-H 200/a-095-A 094-G-01/00 2014 Upper 10,792 6,823 4,441 2.7 10.0

29

Appendix:Egress & Hedging

30

2017 2018 2019

Receipt Point Delivery Point Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4

Enbridge

High Pine Ft. Nelson T-North NGTL or Station 2 240 240 240 240 240 240 240 240 240

Jackfish Lake Ft. St. John T-North Station 2 138 138 138 138 138 138 138 138 138 138 138

Wyndwood Ft. St. John T-North NGTL or Station 2 50 50 50 50 50 50 50 50

Spruce Ridge Program Aitken Creek NGTL or Station 2 402 402

Total Enbridge 138 138 378 428 428 428 428 428 428 830 830

NGTL

Towerbirch Tower Lake or Sunset NGTL 859 859 859 859 859 859 859 859 859

North Montney Aitken Creek NGTL 1,485 1,485 1,485

Total NGTL 859 859 859 859 859 859 2,344 2,344 2,344

Cumulative Total 138 138 1,237 1,287 1,287 1,287 1,287 1,287 2,772 3,174 3,174

Over 3 Bcf/d New Egress Planned Within Three Years

Industry has demonstrated support for multiple expansions

• All six NEBC expansion projects are fully contracted• Spruce Ridge & North Montney are pending regulatory approval, all

other projects are expected to be on-stream as scheduled• Additional expansion projects are expected to be proposed in the near term

Ongoing downstream work being done ahead of anticipated growth

• Additional expansion work and de-bottlenecking is underway on the Alberta system to accommodate the growth and increase the ability for western Canadian gas to access North American markets

Source: Company reports and Black Swan Energy

31

Key Western Canadian Pipelines & Market Hubs

NGTL

ENBRIDGE

ALLIANCE

NORTHERNBORDER

TCPL MAINLINE

GREAT LAKESIROQUOIS

VIKING

ROVER

NEXUS

FOOTHILLS

GTN

VECTOR

CHICAGO

DAWN

AECO

MALIN

SKAB

BC

MB

ONQC

WADDINGTONEMERSONSUMAS

STN 2

HENRY HUB

ROCKIES EXPRESS

NIAGRA

OPAL

RUBY

1. LNG Potential: 4.0+ Bcf/d2. T-South: 1.7 Bcf/d3. NGTL West Gate: 2.0 Bcf/d4. Oil Sands: 1.5 – 2.0 Bcf/d demand 5. Alliance: 1.6 Bcf/d6. AECO: 4.0 Bcf/d

2

3

4

6

5

1

7

8

Infrastructure connects Black Swan to diverse existing and new markets• NEBC Montney is one of the most active natural gas development area

in western Canada • Western Canadian base production declines and new demand will be

predominantly supplied by the Montney• Existing infrastructure capable of delivering ~12 Bcf/d of gas beyond

western Canadian markets (to the US and eastern Canada)

Canadian LNG projects - potential access to offshore markets• Multiple export licenses issued by Canadian government• PETRONAS: PNW cancelled, reviewing other west coast LNG options• LNG Canada (Shell): FID delayed, owners remain supportive• Woodfibre LNG announced approval for funding to proceed Nov 4, 2016

32

Marketing and Risk Management

Third party natural gas processing• 25 MMcf/d firm: McMahon Q4 2015 to Q4 2020

Natural gas egressFrom McMahon• 9.1 MMcf/d Alliance Q4 2015 to Q4 2017 • 4 MMcf/d T-North Q4 2016 to Q4 2018+• 2.8 MMcf/d T-North Q4 2016 to Q4 2028 • 20 MMcf/d T-North Q1 2018 to Q4 2029From North Aitken Creek BSE Plant• 40 MMcf/d T-North Q4 2015 to Q4 2028• 20 MMcf/d Alliance Q2 2017 to Q4 2020• 20 MMcf/d T-North Q3 2017 to Q2 2028• 16.5 MMcf/d T-North Q4 2017 to Q4 2018• 60 MMcf/d T-North Q3 2019 to Q3 2034• 229 MMcf/d North Montney Q2 2019 to Q2 2039

Risk management positions (Aug 31, 2017)

Egress Volumes by Year:2017: 103 MMcf/dT-North Station 2: 83.3 MMcf/dAlliance ATP: 20 MMcf/dAlliance Chicago: 9.1 MMcf/d

2018: 123 MMcf/dT-North Station 2: 103.3 MMcf/dAlliance ATP: 20 MMcf/d

2019: 392 MMcf/dT-North Station 2: 142.8 MMcf/dAlliance ATP: 20 MMcf/dNGTL: 229 MMcf/d

Natural Gas Liquids (C5+/C4)

Station 2 Differential AECO Swaps AECO Costless Collars AECO Puts Chicago Swaps AECO/Chicago Station 2 C$WTI Swaps C$WTI Costless Collars C$WTI

TermVolume (GJ/day)

Price (C$/GJ)

Volume (GJ/day)

Price (C$/GJ)

Volume Put Price Call Price Volume (GJ/d)

Premium (C$/GJ)

Strike (C$/GJ)

Volume (MMBtu/d)

Price (C$/MMBtu)

% Production Volume (bbl/day)

Price (C$/bbl)

Volume Put Price Call Price % Production

GJ/d C$/GJ C$/GJ Hedged Bbl/d C$/Bbl C$/Bbl Hedged

Q3 2017 39,120 ($0.58) 41,986 $2.79 10,000 $2.85 $3.21 6,845 $4.17 55% 37% 967 $65.95 141 $59.09 $73.06 43%

Q4 2017 74,732 ($0.48) 64,636 $2.67 10,000 $2.85 $3.21 9,946 ($0.30) $2.90 2,306 $4.17 58% 50% 834 $65.84 291 $56.77 $68.16 31%

Q1 2018 68,862 ($0.48) 58,910 $2.81 20,000 ($0.34) $2.90 51% 45% 323 $71.68 14%

Q2 2018 62,366 ($0.50) 35,971 $2.69 23% 39% 313 $71.75 13%

Q3 2018 57,084 ($0.50) 35,590 $2.69 22% 36% 303 $71.83 13%

Q4 2018 52,471 ($0.49) 35,260 $2.69 22% 33% 300 $71.85 13%

Q1 2019 49,000 ($0.35) 17,488 $2.77 11% 31% 150 $70.95 9%

Q2 2019 34,330 ($0.37) 1,597 $2.86 1% 13% 127 $70.97 5%

Q3 2019 32,674 ($0.38) 0% 13% 100 $71.00 5%

Q4 2019 20,717 ($0.36) 0% 8% 34 $71.00 4%

2017 48,269 ($0.50) 41,597 $2.77 11,684 $2.83 $3.21 2,507 ($0.30) $2.90 5,540 $4.14 56% 44% 851 $64.94 158 $58.96 $72.79 40%

2018 60,142 ($0.49) 41,352 $2.72 4,932 ($0.34) $2.90 29% 38% 310 $71.78 200 $55.00 $67.25 13%

2019 34,099 ($0.37) 4,710 $2.81 2% 14% 102 $70.98 200 $55.00 $68.00 5%

33

Appendix:Resources & Reserves

34

Substantial Resource to Unlock

Capable of sustaining 2 Bcf/d for 10 years

•Gas-in-place supports long-term growth

•Average 250 Bcf/DSU OGIP

•78 Tcf of gas-in-place

•Over 2,500 Hz well inventory and 14 Tcfe of recoverable resource (two horizons only)

•Potential for development of four horizons

Aitken

Laprise/Sojer

Jedney

1. 4.5 wells/DSU/layer (300 m spacing), two layers developed, ranging from 5.0-9.0 Bcf/well, 90% land utilization2. 4.5 wells/DSU/layer (300 m spacing), four layers developed, ranging from 7.0-11.0 Bcf/well, 90% land utilization

Note: Based on management estimates, liquids converted at 1 bbl: 6 Mcf for gas equivalency, 40 bbl/MMcf liquids and 8% shrinkage

DSUs Base Case1 Upside Estimate2

#Hz Locations

#

Recoverable Resource

Tcfe

Hz Locations

#

Recoverable Resource

Tcfe

Aitken 146 1,176 7.9 2,353 18.2

Laprise/Sojer 102 822 4.1 1,644 11.5

Jedney 64 516 2.6 1,031 7.2

Total 312 2,514 14.6 5,028 37

19% Recovery Factor 47% Recovery Factor

Internal Estimate of Resource

10 km

Legend

1

2

3

4

35

Growth Plan Supported by Low Cost Reserves

16%

25%

44%

2%

1%

12%

2016 Reserves: Value1

$0.00

$2.00

$4.00

$6.00

$8.00

$10.00

$12.00

$14.00

PPY AAV ARX BSE BIR CR PEY BNP TOU SRX NVA KEL VII

$/b

oe

Peer Comparison: 3 Year 2P FD&A (incl. FDC)

1. GLJ January 1, 2017 price forecast, includes 1P FDC $0.9 B and 2P FDC $2.4 B2. Natural gas volumes converted to barrels of oil equivalent at 6,000 cubic feet per barrel (6 mcf = 1 boe)

2016 PDP adds replaced 196% of annual production

Avg: $6.43/boe

2016 Company Interest ReservesNet Present

Value1 Before Tax ($MM)

Gas (MMcf)

NGLs (mbbl)

Total (mboe)2 0% 10%

PDP 190,215 6,344 38,046 649 366

Total proved 850,804 29,010 170,811 2442 898

Proved + probable 2,366,565 83,095 477,522 8,583 2,125

8%

28%

64%

2016 Total Reserves

PDPProved Non-ProducingProbable

32

95

12311

44

104

2016 Reserves: Locations

36

Proved plus probable reserves

• 2016 YE 2P reserves were 478 MMboe, of which 75% are in the Upper Montney where development is focused

• 2P reserves for drilled wells and offset locations are based on test results or longer term production

Infill locations & PUD wells

• GLJ reserves for infill locations assume four wells/layer/DSU and are based on regional performance and OGIP considerations, the Proved component is typically 75 – 80% of the 2P estimate

• GLJ infill type curve assumptions:

• Upper Montney: 7.5-9.0 Bcf

• Lower Montney: 4.5 Bcf

• Infill PUD and Probable locations are booked between economic well tests within 1.5 and 3 miles respectively

• PUD inventory does not exceed five years of drilling

Economics

• GLJ’s economic parameters such as Future Development Capital (FDC), opex and liquid recoveries are in line with BSE’s development plan and are consistent with what they use for other operators

• Year-end valuation is done at GLJ’s Dec 31, 2016 price forecast

• GLJ has booked approximately 50% of what Black Swan considers the core development area

Reserve Booking Methodology

Upper Montney Reserve Booking Map

10 km

37

0%

10%

20%

30%

40%

50%

60%

Jan

Feb

Mar

Ap

rM

ay Jun

Jul

Au

gSe

pO

ctN

ov

Dec Jan

Feb

Mar

Ap

rM

ay Jun

Jul

Au

gSe

pO

ctN

ov

Dec Jan

Feb

Mar

Ap

rM

ay Jun

Jul

Au

gSe

pO

ctN

ov

Dec Jan

Feb

Mar

Ap

rM

ay Jun

2014 2015 2016 2017

Liquids Revenue as % of Total Revenue

0

10

20

30

40

50

60

70

80

90

100

Jan-16 Apr-16 Jul-16 Oct-16 Jan-17 Apr-17 Jul-17

Liq

uid

s Y

ield

(b

bl/

MM

cf)

Black Swan Corporate Liquid Yield

McMahon Black Swan Plant

Black Swan Corporate Black Swan Plant Theorectical

Superior recoveries realized through Black Swan’s North Aitken plant

•Until August 2017 North Aitken was operated to minimize C3 recovery and maximize gas heat content to optimize netbacks (~10 bbl/MMcf C3/C4 vs. design of 20 bbl/MMcf)

•Average McMahon recoveries:

• 19 bbl/MMcf (73% C5+); 11% liquids

•Corporate liquids ratio will increase as Black Swan expands its owned and operated processing capacity and McMahon volumes are a smaller percentage

• Long term expected liquids recovery: 30-50 bbl/MMcf (varying based on propane prices)

Black Swan Liquids Yields

Note: Theoretical based on 20 bbl/MMcf of C3/C4 recovery at refrig design temperature

Black Swan’s plant provides superior liquids yield vs. McMahon

North Aitken plant online

Strong gas prices exiting 2016 lowered the % of

liquids revenue

Liquid Recoveries

August 2017 Average 2016

bbl/MMcf CorporateNorth Aitken Corporate

North Aitken

C5+ 25 31 23 29

C3/C4 19 22 8 11

Total 44 53 31 40

38

Base Decline & Impact of New Production

0

20

40

60

80

100

120

140

160

Jan-14 Jul-14 Jan-15 Jul-15 Jan-16 Jul-16 Jan-17 Jul-17 Jan-18 Jul-18 Jan-19 Jul-19

Gas

Pro

du

ctio

n (

MM

cf/d

)

Black Swan Wells by Vintage

2017 Completions

2016 Completions

2015 Completions

2014 Completions

2012 & 2013 Completions

Base decline on existing wells: ~35%

39

Appendix:Montney Fairway

40

NEBC Growth Driven by Junior/Intermediate Producers

1. Historical Tourmaline production represents Shell prior to the Gundy acquisition; UGR combined with historical Painted Pony production

Industry investment accelerating• Rig activity increasing - 12 rigs operating in Aug 2017 compared

to 1 in Aug 2016• North Montney as high as 1.4 Bcf/d in Jan 2017• Juniors and Intermediates represent ~50% of total North

Montney production up from ~30% three years ago

0

200

400

600

800

1,000

1,200

1,400

1,600

Jan

-14

Mar

-14

May

-14

Jul-

14

Sep

-14

No

v-1

4

Jan

-15

Mar

-15

May

-15

Jul-

15

Sep

-15

No

v-1

5

Jan

-16

Mar

-16

May

-16

Jul-

16

Sep

-16

No

v-1

6

Jan

-17

Mar

-17

May

-17

Avg

Cal

en

dar

Day

Gas

(M

Mcf

/d)

Production Month

North Montney Production

ARC

Todd

Suncor

Conoco

Kelt

Polar Star

Chinook

CNRL

Tourmaline

Saguaro

BSE

Storm

Canbriam

Painted Pony

Progress

June 2015 & 2017 volumes impacted by Enbridge

McMahon turnarounds

Note: Competitor land positions based on public reports and geoSCOUT

20 km

41

Legend

Black Swan Lands

50 m

Siltstone

Siltstone & Sandstone

Sandstone

Montney Isopach Contours

Montney: Proven Top-Tier North American Play

Source: Montney facies base map modified after Canadian Discovery Ltd. (2008)

Black Swan Beg A-020-H/094-G-01

Low

er

Mo

ntn

ey

20

0 m

etr

es

Up

pe

r M

on

tne

y6

5 m

etr

es

100 km

BC

Alb

ert

a

Grande Prairie

Ft St John

•Montney over 250 m thick

•Four landing zones are proven Hz targets either on or immediately adjacent to Black Swan lands

•Consistent, high quality reservoir exhibited across acreage; shelf edge to offshore depositional environment

•Porosity averages 5.0% in the Upper Montney and 4.5% in the Lower. Both zones have very low water saturation

•Favourable stress regime, low clay content and low Poisson’s ratio conducive to effective development of natural and induced fractures

1850

1900

1950

2000

2050

2100