Corporate Presentation May 2017 North Montney: Scale, Growth, Value - - PowerPoint PPT Presentation

Corporate Presentation May 2017

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North Montney: Scale, Growth, Value

Material Scalable Position

• 341 net sections of Montney rights2
• 52 Hz wells drilled at YE ‘16
• Inventory of over 2,800 Hz locations

Strong Balance Sheet Growth Supported by Egress

• Development plan achieves 100,000 boe/d in five years
• Gas egress commitments growing to >395 MMcf/d
• Contracts held on three major pipeline systems

High Quality Asset

• Half-cycle IRR of 75% at $2.50/GJ AECO1
• Average 9 Bcf EUR over last 30 Hz Upper Montney wells
• Recent well costs <$4.0 MM/well
• Liquids yield of 30-50 bbl/MMcf
• $850 MM equity raised to date3 (Azimuth Capital

Management, CPPIB & Warburg Pincus)

• $200 MM bank line4; US$100 MM term debt5
• 1. EUR 9.0 Bcf, US$50/bbl WTI, C$1.25/US$ FX, $0.30/GJ Station 2 differential, $5 MM DCET
• 2. 312 net DSUs where one DSU = 700 acres
• 3. $800 MM drawn, $50 MM undrawn at Mar 31, 2017
• 4. Undrawn post closing of term debt issue
• 5. US dollar denominated, matures Jan 2024, 9% coupon

Liquids-Rich Montney 218,000 net acres 100% working interest

FT ST JOHN EDMONTON

MONTNEY

BRITISH COLUMBIA ALBERTA

10 km

Infrastructure Advantage

• Owned & operated infrastructure ($275 MM at Q2/17)
• Operating cost <$2.50/boe through operated gas plant

3

• 5,000

10,000 15,000 20,000 25,000 Q1 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. Daily Production (boe/d)

Building Momentum Through Pad Drilling

Corporate production

• Dec 2016: 16,650 boe/d (16% liquids)
• Q1 2017: 16,732 boe/d (15% liquids)
• Dec 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

Development Production Growth Delineation

Expansion of owned infrastructure

• 50

100 150 200 250 300 350 400 450 500 2012 2013 2014 2015 2016 Reserves (MMboe) PDP PDNP + PUD Probable

Reserves Growth

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

in Future Development Capital (FDC)

4

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

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)

• 1. Inputs provided in the Appendix
• 2. Black Swan chokes wells during initial production for operational reasons, no material impact on cumulative 365 day production
• 3. Netback over the first year, assumes Station 2 delivery
• 4. 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 Liquids Half-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 30 Upper Montney Hz wells

64% 30% 6% Gas C5+ C3/C4

5 $0.0 $1.0 $2.0 $3.0 $4.0 $5.0 $6.0 $7.0 2014 2015 2016 2017E D&C Costs ($MM/well) Drilling Cost Completion Cost Design Evolution

Ongoing operational success

• Avg EUR: 9.0 Bcf since Q3/13 (30 wells)
• Repeatable and predictable outcomes

Continuous program drives lower costs

• Operational efficiencies of a continuous

program & pad drilling

• Cost reductions from installed water

infrastructure

• Completions timed to minimize costs and fill

processing infrastructure

Evolving Wellbore Design

• Testing well length, proppant loading, stage

count and inter-well spacing to optimize economics:

• Sand loading increased by 30%
• Completed length increased by 50%
• Increased service costs (fracturing)

Repeatable Well Deliverability at Low Cost

Decreasing Costs on Multi-well Pads

$4.2 - $4.8 MM1

• 1. Annual budget $4.5 MM, 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 0.0 2.0 4.0 6.0 8.0 10.0 12.0 14.0

b-B79-G a-A11-A a-B20-H b-A22-C a-92-C c-45-D a-C20-H b-17-H c-B7-H c-A7-H c-7-H b-19-E b-54-D b-A54-D a-54-D a-A54-D a-B54-D a-C54-D b-B54-D a-D54-D b-95-E b-C22-C b-D22-C b-E22-C b-F22-C b-G22-C a-A92-C a-B92-C a-C92-C a-D92-C a-E92-C a-A20-E b-B19-E 2012 2013 2014 2015 2016

Expected EUR (Bcf/well)

Upper Montney Wells (by completion date)

9 Bcf

2012

$6.4 MM $4.6 MM $3.8 MM

6

1,000 2,000 3,000 4,000 5,000 6,000 7,000 8,000 9,000 10,000 30 60 90 120 150 180 210 240 270 300 330 360 390 420 450 480

Mcf/d Normalized Days

Type Curves 7-H Pad Average 19-E Pad Average 54-D Pad Average 22-C Pad Average 92-C Pad Average

Pad Operations Provide Capital Efficient Growth

• 22-C pad paid out in <1 year
• Drilling efficiency4
• Add 17,500 boe/d/rig annually
• F&D cost <$3/boe
• Capital efficiency <$6,000/boe/d

22-C 7 well pad 54-D 8 well pad

10 km

92-C 6 well pad

Pad Year Completed Wells/ Pad Avg D&C ($MM) Avg EUR (Bcf) 7-H 2014 5 6.4 7.21 54-D 2015 8 4.6 8.4 22-C 2015 7 4.1 10.31 92-C 2016 6 3.9 9.7 19-E 2015/2016 3 3.72 9.7

10.5 Bcf 9.0 Bcf 7.5 Bcf

Upper Montney Multi-Well Pad Performance Tracking Type Curves

22-C delivering >130% IRR3

7-H 5 well pad 19-E 3 well pad

• 1. Pads incl. one Lower Montney pilot well not incl. in avg. EUR
• 2. Avg cost for two 2016 wells, 2015 well cost $9 MM D&C
• 3. At $2.50/GJ AECO and US$50/bbl WTI
• 4. Based on IP 365 of 875 boe/d (half-cycle 9.0 Bcf EUR type curve, $5 MM DCET)

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Infrastructure Advantage

North Aitken Creek Gas Plant 110 MMcf/d capacity

North Aitken Plant Compressors

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+)
• Phase 2 on-stream scheduled June 2017

Plant 2: 198 MMcf/d facility

• Engineering in progress
• Long lead equipment included in 2017 budget
• Expect Phase 1 on-stream Q4 2018

Infrastructure investment

• At 2016 YE: $220 MM
• 2017 Budget: $92 MM

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”

110 MMcf/d raw capacity

10 km

Pipeline infrastructure in place to support >110 MMcf/d at plant

• 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)

Existing gathering trunk-lines

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$15.06 $6.48 $1.46 $2.50 $1.60 $1.26 $0.00 $5.00 $10.00 $15.00 $20.00 $25.00 Costs Revenues

$/boe

North Aitken Gas Plant Q1 2017 Operating Netback

Royalty Transportation Operating Cost C3/C4 Revenue C5+ Revenue Gas Revenue

Low Cost Growth: Owned & Operated Gas Plant

Phase 1 capacity: 10,000 boe/d

• Plant optimized to maximize netbacks:
• Condensate/C5+ yield: >20 bbl/MMcf
• C3/C4 yield: 10 bbl/MMcf
• Gas heat content: 1,170 MMbtu/mcf
• Recent wells initially at total C5+ yields as high as

40 bbl/MMcf

• Stable total C5+ yield: 20 bbl/MMcf
• Capable of increasing C3/C4 to 20 bbl/MMcf

Operating netback reflects ownership advantage

• Operating costs <$2.50/boe
• Plant operating netbacks >$17.50/boe in Q1/17
• Produced water recycled for ongoing operations

10 20 30 40 50 60 70 80 90 100 10 20 30 40 50 60

Jan-16 Mar-16 May-16 Jul-16 Sep-16 Nov-16 Jan-17 Mar-17

Liquids Yield (bbl/MMcf) Gas Production (MMcf/d)

North Aitken Creek Gas Plant Production

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

Field netback $17.64/boe

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North Aitken Plant – Phase 2 Commissioning June 2017

2016: Phase 1 Q1 2016 2017: Phase 2 Expansion Q2 2017

Additional liquids handling Increased gas through put capacity

10 $15.79 $5.92 $1.12 $0.20 ($0.24) $4.14 $2.37 $1.14 $1.37 $1.87

• $5.00

$0.00 $5.00 $10.00 $15.00 $20.00 $25.00 Costs Revenues 2017E $/boe

2017E Revenues vs. Costs

Interest Royalty G&A Transportation Operating Cost Hedging Processing Income C3/C4 Revenue C5+ Revenue Gas Revenue 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 Daily Production (boe/d)

Black Swan Production1

Actuals (Gas) Actuals (Liquids) Base Decline Completed awaiting capacity 2017 Completions

Inventory Feeds H1/17 Production, New Wells Fill Plant Expansion

Cash flow netback $11.91/boe2

Forecast

• n-stream

tied-in 2017 completions North Aitken Plant Phase 2 on-stream North Aitken Plant & Enbridge McMahon Turn Arounds

Corporate production at record rates Production outlook

• Production to exceed 25,000 boe/d with

the North Aitken plant expansion commissioning

Cost structure

• Operating and corporate costs per boe

trending lower as more production flows through Black Swan facilities

Dec-16 Jan-17 Feb-17 Mar-17 Average (boe/d) 16,650 16,730 16,750 16,720 % liquids 16% 15% 15% 15%

• 1. Production shut in at 22-C during April 2017 to accommodate completion of the 2-C pad
• 2. Based on annual production of ~18,500 boe/d at $2.77/GJ AECO, -$0.41/GJ Station 2 to

AECO differential, US$49/bbl WTI and $1.35 C$/US$

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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

Corporate production

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

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
• Commissioning June 2017
• Long lead items for 198 MMcf/d Plant 2

Funding1

• 2017E cash flow from operations: $80 - $85 MM
• 2017E year-end net debt: $185 - $ 190 MM
• Expect to draw less than $50 MM of the

existing $200 MM bank facility

• 5,000

10,000 15,000 20,000 25,000 30,000 Q4 2016 Q4 2017E Production (boe/d)

Over 60% Production Growth Y/Y

• 1. Based on annual production of ~18,500 boe/d at $2.77/GJ AECO, -$0.41/GJ Station 2

to AECO differential, US$49/bbl WTI and $1.35 C$/US$

12 100 200 300 400 500 600 Jan Apr Jul Oct Jan Apr Jul Oct Jan Apr Jul Oct Jan Apr Jul Oct Jan Apr Jul Oct Jan Apr Jul Oct 2017E 2018E 2019E 2020E 2021E 2022E

Gas (MMcf/d)

Egress Commitments vs. Planned Plant Capacity

Enbridge Alliance NGTL Planned Plant Capacity (Raw)

Growth Underpinned With Firm Service

McMahon Gas Plant Sunset T-South to Huntington/Sumas Station 2 Aitken Creek Gas Storage NGTL to AECO North Aitken Gas Plant BRITISH COLUMBIA ALBERTA

25 km

3

Long term visibility

• Egress committed on all three Canadian pipeline systems2
• Pipeline capacity beyond planned processing capacity4

represents an opportunity to:

• Accelerate the development plan, or
• Maximize netbacks through sales point optimization
• 1. NGTL is part of the TransCanada pipeline system
• 2. North Montney Mainline project is subject to regulatory approval, on-stream est. Q2/19
• 3. Includes Black Swan owned & operated processing & existing McMahon commitments
• 4. Excess capacity in 2019 & 2020 provides the opportunity for potential acceleration of

development; cost of unutilized excess capacity: $9.8 MM in 2019 & $5 MM in 2020

Egress beyond planned plant capacity provides opportunity to accelerate

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

92-C pad EUR = 10 Bcf 54-D pad Avg EUR = 8 Bcf 22-C pad Avg EUR = 10 Bcf 19-E pad

• Avg. EUR = 9 Bcf

10 km

7-H pad Avg EUR = 7 Bcf Aitken Core Development Area

• 1. Drilling plans are subject to annual review and may be modified

based on factors including: commodity prices, facility access and regulatory constraints 45-D well EUR = 11 Bcf

Development plan1 uses <20% of inventory

• Upper Montney delineated across the Aitken core

development area; 430 Hz locations remaining

• Drilling over next five years: ~200 Hz wells
• Plan contains 230 additional Upper Montney Hz

locations to maintain 100,000 boe/d for eight years

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

Aitken core development plan well defined; future upside in

• ngoing delineation on

northern acreage

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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

$/boe

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

Low Cost Reserves Underpin Growth Plan

• 1. GLJ January 1, 2017 price forecast, includes 1P FDC $0.9 B and 2P FDC $2.4 B
• 2. 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 Reserves Net 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

PDP Proved Non-Producing Probable 32 95 123 11 44 104

2016 Reserves: Locations

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• 5,000

10,000 15,000 20,000 25,000 30,000 35,000 40,000 45,000 Jun - Dec 2017 2018 2019

Hedged Volumes (GJ/d)

Annual Hedging & Average Contract Pricing

Station 2 Diff ($/GJ) AECO Swaps ($/GJ) AECO Collars ($/GJ) AECO Puts ($/GJ) Chicago Swaps (C$/MMBtu) 100 200 300 400 500 600 700 Jun - Dec 2017 2018 2019

C4 & C5+ Production (boe/d)

Liquids Hedging & Average Contract Pricing

Swaps Collars

• 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

Risk Management & Pricing

• $0.54

$2.82

• $0.23
• $0.37

$2.77 $2.86 $2.85 x $3.21 $4.17

Gas volumes are delivered primarily to Station 2 Liquids (C4 & C5+) represent >20% of revenue & priced vs. WTI

$63.98 $71.78 $70.98 $60.00 x $75.00 $2.60 $2.57

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

3% 49% 1% 43% 4%

Jun - Dec 2017 Gas Pricing Portfolio

Unhedged AECO Unhedged Station 2 Unhedged Chicago Hedged AECO Hedged Chicago 23% 77%

Jun - Dec 2017 Liquids (C4 & C5+) Pricing

Hedged Unhedged

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Source Water Secured for Development Plan

Beatton River water license

• License supports:
• Peak drilling rate of 100+ Hz wells/year
• Development to achieve 100,000 boe/d in

five years

• 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
• Water handling infrastructure is temporary by

design to allow flexibility of operation and

• ptimization of capital

Water License Intake 1 Water Pump Station

b-54-D Fresh Water Pit 65,825 m³ c-7-H Fresh Water Pit 60,300 m³ capacity Water pump station

• 1. Subject to renewal provisions

d-42-D Fresh Water Pit 65,000 m³ b-11-A Fresh Water Pit 44,900 m³

10 km

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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 100 200 300 400 500 600 700 800 Progress Black Swan CNQ Saguaro TOU CR ARX PPY SRX SU ECA CKE Canbriam RDS LXE TODD/POU COP KEL PGF MUR Net DSUs2

Dominant Position in Over-Pressured, Liquids-Rich Fairway

Upper Montney Oil Window

Normally Pressured

Upper Montney Dry Gas

Alberta B.C. Caribou Umbach Town Altares Septimus Groundbirch Swan Parkland Aitken Beg Jedney Laprise

Montney Hz post 2013

Legend

Montney Hz Black Swan land Liquids-rich gas window Dry gas window Oil window (>75 bbl/MMcf) Montney TVD contour

1600m 25 km

Upper Montney Over-Pressured Liquids-Rich Fairway Black Swan holds the second largest liquids-rich position in the NEBC Montney fairway

Liquids Rich Montney Rights

• 1. Expected shallow cut recovery
• 2. Source: Black Swan, geoSCOUT and company reports

Dry gas Oil Black Swan

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$0.0 $2.0 $4.0 $6.0 $8.0 $10.0 $12.0

D&C Cost $MM

Drilling & Completion Cost (2016)

0% 20% 40% 60% 80% 100%

Gas Weighting

Gas Weighting (2016)

$0.00 $2.00 $4.00 $6.00 $8.00 $10.00 $12.00

2017E $/boe

Operating Cost (2017E)

0.0 2.0 4.0 6.0 8.0 10.0 12.0

EUR (Bcf)

EUR1 – Wells Drilled in Last Three Years

Differentiation: Performance on Multiple Factors vs. Peers

Well performance Leading capital efficiencies Infrastructure advantage Liquids contribution

Black Swan Full Cycle Forward Economics2

$/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. Internal estimates, Montney gas & liquids rich wells
• 2. Inputs based on $2.50/GJ AECO, $50/bbl WTI, 9 Bcf type

curve and expected five year growth profile BSE Plant (excl. McMahon production) BSE 8.3 BSE 3.8 BSE 4.11 BSE 84% Source: Internal estimates & company reports Peer group includes: AAV, ARX, BIR, Canbriam, CR, KEL, NVA, PPY, Saguaro, SRX, TOU, VII

• Incl. three Lower Montney wells

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Strategic Focus – Long-term, Scalable, Low Cost Development

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

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Appendix: Corporate & Financial Summary

21

Management Team

• David Maddison, P.Eng. – President and CEO (Talisman Energy, BP Exploration)
• Marc Mereau, P.Eng. – COO (Talisman Energy, BP Canada)
• Michael Wilhelm, B.Comm., CPA, CGA – CFO & VP Finance (Peloton Exploration, Espoir Exploration)
• Bruce Thornhill, P.Geol. – VP Exploration (TAQA North, PrimeWest, Shiningbank, Chevron)
• Bryan Lang, P.Eng. – VP Operations (Peyto Exploration, Northrock Resources, Chevron)
• Diane Shirra, P.Eng, MBA – VP Business Development (Pengrowth Corp., Canetic, Poco Petroleums)
• Leanne Juneau, B.Comm. – VP Land (Redcliffe Exploration, Talisman Energy, Northrock Resources)
• Christine Ezinga, B.Comm., CFA – VP Strategy & Planning (Sinopec, Daylight Energy, CIBC World Markets)

Board of Directors Independent Board Members

• Jim Buckee – Independent Board member, formerly President & CEO of Talisman Energy Inc.
• Jackie Sheppard (Lead Director) – Independent Board member, formerly Executive Vice-President, Corporate and

Legal and Corporate Secretary for Talisman Energy Investor/Management Board Members

• Roy Ben-Dor – Warburg Pincus
• David Krieger – Warburg Pincus
• David Maddison – Black Swan
• Robert Mellema – CPP Investment Board
• Jim Nieuwenburg – Azimuth Capital Management
• David Pearce – Azimuth Capital Management

Black Swan Energy Management and Directors

22

Historical Financial Summary

• 1. Preliminary, subject to Audit Committee approval
• 2. 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 Q11 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)

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) 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) 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 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 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 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) 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) (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 76,555 76,555 68,258 65,180 60,538 555 50,000 25,000 Term Notes 128,867 Total Net Debt 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 200,000 200,000 200,000 140,000 140,000 130,000 130,000 130,000 80,000 70,000 70,000 40,000 40,000 24,000 24,000 12,000 Netback Summary ($/boe) Net Revenue 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) (0.20) 0.87 (1.28) 0.44 2.46 2.60 0.33 0.60 (0.04) 0.60 0.15 0.00 0.00 0.00 0.00 0.00 Royalties (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 (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 (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 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 (1.27) (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 0.20 0.27 0.19 0.38 0.19 0.37 0.47 1.61 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 Interest/Other Expense (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 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

26 200 400 600 800 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 2 4 6 8 10 12 14 16 18 20 Depth (mMD) 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

• perations
• 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
• verall 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/yr

• Drilling cost per meter reduced in 2017 with

improved drilling efficiency and longer laterals

Build section (turn to Hz) Change to slim Hz drilling assembly Set packers, cement, rig out Preset Rig Pad Rig Move pad rig, install BOP Preset surface, skid rig

27

Completions – Optimization of Design

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
• 2016/2017 –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

2012 2013 2014 2015 2016 2017 55 75 95 115 135 155 175 195 215

mMD

Stage Spacing

2012 2013 2014 2015 2016 2017 1400 1600 1800 2000 2200 2400 2600

mMD

Completed Well Length

2012 2013 2014 2015 2016 2017 0.50 0.60 0.70 0.80 0.90 1.00 1.10 1.20 1.30 1.40 1.50

tonne/m

Proppant Concentration

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 IP365 Cum to Mar/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 awaiting tie in c-D2-C 200/b-100-J 094-A-13/00 2017 Upper awaiting tie in c-C2-C 200/a-100-J 094-A-13/00 2017 Upper awaiting tie in c-B2-C 200/c-025-C 094-H-04/00 2017 Upper awaiting tie in c-A2-C 200/b-035-C 094-H-04/00 2017 Upper awaiting tie in c-2-C 200/a-035-C 094-H-04/00 2017 Upper awaiting tie in 19-E Well Pad b-B19-E 200/b-097-D 094-H-04/00 2016 Upper 3,240 NA NA 9.5 a-20-E 200/c-088-D 094-H-04/00 2016 Upper 5,000 4,448 NA 0.5 9.1 b-19-E 200/b-098-D 094-H-04/02 2015 Upper 5,701 5,129 4,617 2.1 10.0 92-C Well Pad a-B92-C 200/c-004-F 094-H-04/00 2016 Upper 5,917 NA NA 0.5 10.1 a-A92-C 200/a-014-F 094-H-04/00 2016 Upper 6,126 NA NA 0.3 11.6 a-E92-C 200/b-080-B 094-H-04/00 2016 Upper 4,847 NA NA 0.3 8.3 a-D92-C 200/a-080-B 094-H-04/00 2016 Upper 4,833 4,317 NA 0.7 8.6 a-C92-C 200/d-080-B 094-H-04/00 2016 Upper 3,774 NA NA 0.2 8.7 a-92-C 200/d-004-F 094-H-04/02 2013 Upper 5,886 5,951 NA 0.9 10.5 22-C Well Pad b-G22-C 202/b-010-B 094-H-04/00 2015 Upper 7,343 6,450 NA 1.5 10.0 b-F22-C 200/d-010-B 094-H-04/00 2015 Upper 5,790 6,375 5,217 1.8 10.5 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 NA 1.6 11.0 b-C22-C 200/a-044-C 094-H-04/00 2015 Upper 6,522 5,783 NA 1.2 10.3 b-A22-C 200/c-010-B 094-H-04/02 2013 Upper 6,521 5,900 NA 1.5 9.0 54-D Well Pad a-D54-D 200/a-075-D 094-H-04/00 2015 Upper 4,428 4,431 3,697 1.5 8.6 b-B54-D 200/b-075-D 094-H-04/00 2015 Upper 4,659 4,587 3,367 1.3 7.5 a-C54-D 202/d-066-D 094-H-04/00 2015 Upper 4,520 4,271 3,454 1.4 8.1 a-B54-D 200/d-066-D 094-H-04/00 2015 Upper 5,065 4,602 3,336 1.3 8.1 a-A54-D 202/a-032-D 094-H-04/00 2015 Upper 6,893 6,042 4,695 1.8 8.6 a-54-D 200/a-032-D 094-H-04/00 2015 Upper 3,913 4,201 NA 1.3 8.6 b-A54-D 200/b-032-D 094-H-04/00 2015 Upper 5,368 4,949 NA 1.3 8.1 b-54-D 200/a-033-D 094-H-04/00 2015 Upper 5,284 5,080 NA 1.3 7.7 7-H Well Pad c-B7-H 200/b-095-A 094-G-01/02 2014 Upper 4,233 2,922 3,137 1.7 7.5 c-A7-H 202/a-096-A 094-G-01/00 2014 Upper 4,870 4,274 2,738 1.5 6.0 c-7-H 200/b-096-A 094-G-01/00 2014 Upper 7,506 4,559 3,171 1.6 6.0 b-17-H 200/a-095-A 094-G-01/00 2014 Upper 10,792 6,823 4,441 2.5 9.8

29

Appendix: Egress & Hedging

30

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
• 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

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 2 240 240 240 240 240 240 240 240 240 240 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 2 402 402 402 402 402 Total Enbridge 138 378 378 428 428 428 830 830 830 830 830 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 138 378 1,237 1,287 1,287 1,287 1,689 1,689 3,174 3,174 3,174

31

Infrastructure connects Black Swan to diverse existing and new markets

• NEBC Montney is 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) More than 4 Bcf/d planned take away to new offshore markets

• Multiple LNG projects slowly advancing
• PNW LNG (PETRONAS) is the largest of

the leading projects; LNG Canada FID has been delayed

• Woodfibre LNG announced approval for

funding to proceed Nov 4, 2016

Leveraging Infrastructure to Access Diverse Markets

TransCanada (NGTL)

PNW LNG LNG Canada

AECO

Stn 2 Sumas

VANCOUVER EDMONTON

MONTNEY

Kingsgate

BRITISH COLUMBIA ALBERTA

CALGARY

Woodfibre LNG AB oil sands 2.0 – 2.5 Bcf/d demand 6.0 Bcf/d (4.2 Bcf/d)

~14 additional LNG export projects have been proposed and are at various stages of planning and/or approval for the west coast with Black Swan’s lands being well positioned to supply natural gas as feedstock

4+ Bcf/d potential Prince Rupert Pipeline Coastal Gaslink

Western Canada Pipeline Capacity & (Flows)

32

Marketing and Risk Management

Third party natural gas processing

• 25 MMcf/d firm: McMahon Q4 2015 to Q4 2020

Natural gas egress From McMahon

• 9.1 MMcf/d contract on Alliance Q4 2015 to Q4 2017
• 4 MMcf/d on T-North Q4 2016 to Q4 2018
• 2.8 MMcf/d on T-North Q4 2016 to Q4 2028
• 20 MMcf/d on T-North Q1 2018 to Q4 2029

From North Aitken Creek BSE Plant

• 40 MMcf/d on T-North Q4 2015 to Q4 2028
• 20 MMcf/d on Alliance Q2 2017 to Q4 2020
• 20 MMcf/d on T-North Q3 2017 to Q2 2028
• 16.5 MMcf/d on T-North Q4 2017 to Q4 2018
• 60 MMcf/d on T-North Q4 2018 to Q4 2033
• 229 MMcf/d on North Montney Q2 2019 to Q2 2039

Risk management positions (May 12, 2017)

Natural Gas Liquids AECO Swaps Station 2 Differential AECO Costless Collars AECO Puts Chicago Swaps C$WTI Swaps C$WTI Costless Collars Term Volume (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$/MMBtu) Volume (bbl/day) Price (C$/bbl) Volume Put Price Call Price GJ/d C$/GJ C$/GJ Bbl/d C$/Bbl C$/Bbl Q2 2017 32,683 $2.79 31,681 ($0.53) 10,000 $2.85 $3.21 6,845 $4.17 800 $63.98 100 $60.00 $75.00 Q3 2017 41,986 $2.79 31,663 ($0.56) 10,000 $2.85 $3.21 6,845 $4.17 600 $63.90 100 $60.00 $75.00 Q4 2017 42,773 $2.87 40,946 ($0.53) 10,000 $2.85 $3.21 9,946 ($0.20) $2.90 2,306 $4.17 534 $63.86 100 $60.00 $75.00 Q1 2018 48,910 $2.87 45,656 ($0.53) 20,000 ($0.34) $2.90 323 $71.68 Q2 2018 30,971 $2.74 34,330 ($0.52) 313 $71.75 Q3 2018 30,590 $2.74 33,337 ($0.53) 303 $71.83 Q4 2018 30,260 $2.74 39,134 ($0.51) 300 $71.85 Q1 2019 12,488 $2.85 36,344 ($0.37) 150 $70.95 Q2 2019 1,597 $2.86 34,330 ($0.37) 127 $70.97 Q3 2019 32,674 ($0.38) Q4 2019 20,717 ($0.36) 2017 36,086 $2.82 37,874 ($0.51) 11,684 $2.83 $3.21 2,507 ($0.30) $2.90 5,540 $4.14 682 $63.93 100 $60.00 $75.00 2018 35,119 $2.77 38,083 ($0.52) 4,932 ($0.34) $2.90 310 $71.78 $0.00 $0.00 2019 3,477 $2.86 30,978 ($0.37) 102 $70.98 $0.00 $0.00

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 2,800 Hz well inventory and 16 Tcfe of

recoverable resource (two horizons only)

• Potential for development of four horizons

Aitken Laprise/Sojer Jedney

1.Five wells/DSU/layer (300 m spacing), two layers developed, ranging from 4.6-7.5 Bcf/well, 90% land utilization 2.Six wells/DSU/layer (250 m spacing), four layers developed, ranging from 6.0-9.0 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 1,320 8.0 3,150 21.3 Laprise/Sojer 102 916 5.1 2,203 14.1 Jedney 64 575 3.2 1,380 8.8 Total 312 2,811 16.3 6,733 44.2 21% Recovery Factor 57% Recovery Factor

Internal Estimate of Resource

10 km

Legend

1 2 3 4

35

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

36

10 20 30 40 50 60 70 80 90 100 Jan-16 Feb-16 Mar-16 Apr-16 May-16 Jun-16 Jul-16 Aug-16 Sep-16 Oct-16 Nov-16 Dec-16

Liquids Yield (bbl/MMcf)

Black Swan Corporate Liquid Yield

McMahon Black Swan Plant Black Swan Corporate Black Swan Plant Theorectical

• Average 2016 corporate recoveries:
• 31 bbl/MMcf (73% C5+)
• Black Swan North Aitken 2016 recoveries:
• 40 bbl/MMcf (72% C5+); 19% liquids
• The facility is capable of producing an

additional 10 bbl/MMcf of C3/C4; however, is currently being operated to minimize C3 recovery and maximize gas heat content to optimize netbacks

• Lower recoveries through McMahon:
• 19 bbl/MMcf (73% C5+); 11% liquids
• As Black Swan expands processing capacity

the corporate liquids ratio will increase as production through McMahon becomes a smaller percentage

• Long term Black Swan expects to recover

total liquids of 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 with additional upside should propane prices improve

0% 10% 20% 30% 40% 50% 60% Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec 2014 2015 2016

% of Total Revenue

Liquids Revenue as % of Total Revenue

North Aitken

plant online

Strong gas prices exiting 2016 lowered the % of liquids revenue

37

Base Decline & Impact of New Production

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 Production (MMcf/d)

Black Swan Wells by Vintage

2017 Completions 2016 Completions 2015 Completions 2014 Completions 2012 & 2013 Completions

Base decline on existing wells: 25-30%

38

Appendix: Montney Fairway

39

NEBC Growth in 2017 Driven by Junior/Intermediate Producers

Industry investment accelerating

• North Montney production of 1.37 Bcf/d at March 2017

Note: Competitor land positions based on public reports and geoSCOUT 1. Historical Tourmaline production represents Shell prior to the Gundy acquisition Historical Painted Pony production is combined with UGR production

200 400 600 800 1,000 1,200 1,400 1,600 Jan-14 Mar-14 May-14 Jul-14 Sep-14 Nov-14 Jan-15 Mar-15 May-15 Jul-15 Sep-15 Nov-15 Jan-16 Mar-16 May-16 Jul-16 Sep-16 Nov-16 Jan-17 Mar-17

Average Calendar Day Gas (MMcf/d) Production Month

North Montney Production1

ARC Kelt Todd Conoco Suncor Chinook CNRL Tourmaline Saguaro Storm Black Swan Canbriam Painted Pony Progress

20 km

40 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

Lower Montney 200 metres Upper Montney 65 metres

100 km

BC Alberta 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

• f natural and induced fractures

1850 1900 1950 2000 2050 2100

41

Appendix: Benchmarking

42

Top Tier Montney Ranking

0% 10% 20% 30% 40% 50% 60% 70% 80% 90% 100% 0.0x 0.2x 0.4x 0.6x 0.8x 1.0x 1.2x 1.4x 1.6x 1.8x

YO - Inga/Fireweed Montney CR - Greater Portage Montney VII - Route - Upper/Middle Montney TOU - Deep Basin Montney Canbriam - South Fault Block (Altares) COP - Blueberry Montney LRNG ATH/MUR - Placid Montney (LRNG) RMP - Kaybob Montney VII - Kakwa - Lower Montney Progress - NEBC Caribou Montney Front Range - Alberta Deep Basin Montney - Harley RDS - Groundbirch Canbriam - North & East Fault Blocks (Altares) KEL - Inga/Fireweed Middle Montney KEL - Pouce Coupe Upper Montney BIR - Elmworth - Upper Montney (D5/D4) CR - West Groundbirch Montney LRNG TET - Presley Montney Hz Canbriam - Main Fault Block (Altares) - L. Montney NVA - Wapiti/Bilbo Montney LRNG - Base RDS - NW Groundbirch POU - Valhalla Montney CQE - Simonette Montney - Base Case NVA - Pipestone/Elmworth Montney NVA - Elmworth/Wapiti Montney LRNG DEE - Bigstone Montney (LRNG) CKE - Knopcik Montney ARX - Attachie Montney KEL - Inga/Fireweed Upper Montney BIR - Pouce Coupe Lower Montney (D1) BIR - Pouce Coupe Upper Montney (Basal Doig/D5/D4) ECA/MUR - Dawson South-Tupper BSE - Jedney Montney TOU - NEBC Montney (Sunset/Sunrise/Sundown) BIR - Pouce Coupe Middle Montney (D2) CKE - Birley/Umbach Montney VII - "Nest 1" Upper/Middle Montney POU - Karr/Gold Creek Montney CR - Attachie Montney LRNG KEL - Karr Montney - LRNG LXE - NEBC Lower Montney Hz - LRNG POU - Birch Montney TOU - NEBC Montney (Regional LRNG) ARX - Parkland Montney Canbriam - Main Fault Block (Altares) - U. Montney NVA - Wapiti/Bilbo Montney LRNG - High SRX - Umbach Montney - South Block AAV - Glacier Lower Montney Saguaro - Laprise - Upper/Middle Montney ARX - Dawson Montney CR - Septimus Lower Montney LRNG ARX - Dawson Lower Montney SRX - Umbach Montney - North Block ECA - Pipestone Montney - Super Condensate VII - "Nest 2" Upper/Middle Montney TOU - NEBC Montney (Lower Montney Turbidite LRNG) AAV - Glacier Upper Montney PPY - NEBC Blair/Daiber Montney CR - West Septimus Montney LRNG ARX - Sunrise Montney AAV - Glacier Middle Montney BSE - Aitken Montney PPY - NEBC Townsend Montney ECA - South Dawson - Lower Montney ECA - Pipestone Montney - LRNG ECA - Tower - Natural Gas ECA - Saturn CR - Septimus Upper Montney LRNG

IRR (Atax) PIR (Atax, 10%)

PIR (FCC) PIR (Strip) IRR (FCC) IRR (Strip) Note: PIR is calculated by taking the net present value (discounted at 10%) divided by the capital expenditures Source: GMP FirstEnergy Research

With an inventory of over 2,800 Hz Montney locations across its asset base Black Swan is well positioned to deliver long term growth

Montney Natural Gas Project Economic Comparison

2017e FCC Pricing (WTI US$60/bbl, Ed. Light C$63.78/bbl, Condensate C$67.27/bbl, NYMEX US$3.38/mmbtu, AECO C$3.11/mcf, USD/CAD $0.86) 2017e Current Strip Pricing (WTI US$48.39/bbl, Ed. Light C$59.99/bbl, Condensate C$61.20/bbl, NYMEX US$3.14/mmbtu, AECO C$2.92/mcf, USD/CAD $0.76) (September 2016)

43 0% 10% 20% 30% 40% 50% 60% 70% Black Swan Montney (9 Bcf) Bakken Tier 1 Midland Lower Spraberry Eagle Ford Wet Gas TFS Tier 1 Eagle Ford Condensate Tier 1 Marcellus Dry Tier 1 Eagle Ford Oil Tier 1 Haynesville Black Swan Montney (7.5 Bcf) Delaware Bone Spring Delaware Avalon Niobrara Tier 1 Delaware Wolfcamp (North) Delaware Wolfcamp (South) Midland Wolfcamp Tier 1 STACK Cleveland Core New Mexico Shelf Eagle Ford Oil Tier 2 Midland Wolfcamp Tier 2 Legacy CanaTier 1 Utica Dry TFS Tier 2 Jonah/Pinedale Tier 1 Niobrara Tier 2 San Juan Marcellus Dry Tier 2 Marcellus Wet Legacy CanaTier 2 Bakken Tier 2 Eagle Ford Condensate Tier 2 Utica Condensate Utica Wet Tier 1 Fayetteville Utica Wet Tier 2 Before Tax IRR (%)

Resource Play Benchmarking at US$50/bbl WTI & US$3.00/MMBtu NYMEX (half-cycle)1,2

Comparative Ranking Among Top US Plays

Source: Tudor Pickering Holt & Co. (March 2017) Black Swan economics compare favorably to top US plays

• 1. Half-cycle economics for US plays assumes 40% NGL realization and 20% royalty
• 2. Black Swan economics reflect US$3.00 NYMEX which assumes US$1.33/C$ and US-$1.20/MMBtu differential, which approximates a $2.34/mcf gas price (prior to heat content adjustments)

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$0.00 $4.00 $8.00 $12.00 $16.00 $20.00 RRC AR SWN COG GPOR EQT RICE Black Swan

C$/boe

2016 Corporate Revenues, Costs & Cash Netbacks1,2

Cash Netback Cash Costs

US Investor Presentations are stating forward looking economics that show significant improvement compared to historical data.

BTAX IRR Ranking (US$50/bbl WTI & US$3/mcf HHUB)

March 2017 IR Presentations – US$3 HHUB with forward looking projections TPH Research View - US$3 HHUB with historical well results

Cost Structure Supports Top Tier Ranking vs. Marcellus/Utica Producers

• 1. US$ converted to C$ at 1.30
• 2. Revenue excludes hedging, cash costs include royalties or ad valorem tax, operating, net marketing cost or revenue, transportation and processing costs

Source: Corporate reports and Black Swan Energy

Montney Marcellus

Total revenue1

Source: Tudor, Pickering Holt & Co.

Cost structure supports highly competitive cash netbacks