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

Corporate Presentation January 2017

2

North Montney: Scale, Growth and Value

Material Position

• 341 sections of Montney rights2
• Contiguous, 100% WI with liquids-rich potential
• Over 78 Tcf of estimated gas-in-place

Well Financed High Growth Potential

• Capable of achieving 100,000 boe/d in five years
• 52 Hz wells drilled at year-end 2016
• Inventory of over 2,800 Hz locations

High Quality Asset

• Well results indicate 7-11 Bcf EUR at low cost
• Liquids yield of 35-50 bbl/MMcf
• Half-cycle IRR of 75% at $2.50/GJ AECO1
• $850 MM equity raised to date3
• Investors: Azimuth Capital Management, Canada

Pension Plan Investment Board & Warburg Pincus

• $200 MM bank line4
• 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 Dec 31, 2016
• 4. $123 MM undrawn at Dec 31, 2016

NEBC Liquids-Rich Montney 218,000 net acres

FT ST JOHN EDMONTON

MONTNEY

BRITISH COLUMBIA ALBERTA

10 km

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: Development Drilling & Infrastructure

Corporate production

• Dec 2016: 16,500 boe/d (16% liquids)
• Dec 2017 budget: 24,000 – 26,000 boe/d (17% liquids)

Capital program

• Focused on multi-well development pads
• 2016: $89 MM (incl. $50 MM infrastructure)
• 8 Hz wells drilled, 8 completed, 16 tied in
• 2017 budget: $180 MM (incl. $92 MM infrastructure)
• 19 Hz wells drilled, 16 completed, 16 tied in
• North Aitken Creek expansion to 110 MMcf/d
• Long-lead items for second gas plant

2015 YE reserves - independent evaluation1

• 1P = 127 MMboe (NPV10 $725 MM)
• 2P = 383 MMboe (NPV10 $1,727 MM)
• F&D (incl. FDC)2,3: 1P $6.84/boe; 2P $2.55/boe
• FD&A (incl. FDC)3: 1P $8.37/boe; 2P $3.70/boe
• 50

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

Reserves Growth

• 1. Evaluated by GLJ, Montney only - excludes Duvernay which was divested April 2016
• 2. Excludes Carmel Bay acquisition
• 3. Capital costs include the cost of the North Aitken Creek Gas Plant & land

Development Production Growth Delineation

Expansion of owned infrastructure

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. Netback over the first year, assumes Station 2 delivery
• 3. At $2.50/GJ AECO, US$50/bbl WTI, C$1.25/US$ FX and -$0.30/GJ Station 2 diff

9.0 Bcf Wells Breakeven: US$50/bbl WTI: ~$0.85/GJ AECO US$60/bbl WTI: ~$0.60/GJ AECO

Assumptions D&C Cost ($MM, excl. $0.4 MM tie-in) $4.6 EUR (Bcf) 9.0 IP30 - Gas (MMcf/d, raw) 7.0 IP30 - Total (boe/d) 1,300 Heat Content (MMBtu/mcf) 1,150 Liquids Yield (bbl/MMcf) 40 Royalty Drilling Credit ($ MM) $1.05 Opex & Transport ($/boe) $4.30

62% 29% 8% Gas C5+ C3/C4

Revenue Enhanced by Liquids Half-cycle Revenue Mix at 40 bbl/MMcf3

• 500

1,000 1,500 2,000 2,500

• 2,000

4,000 6,000 8,000 10,000 1 30 59 88 117 146 175 204 233 262 291 320 349 378 407 436 465 494 523 552 581 610 639 668 697 Cumulative Production (MMcf) Daily Production (mcf/d) Days on Production

Unrestricted vs. Restricted Type Curve

Unrestricted 9 Bcf Restricted 9 Bcf Unrestricted Cum Restricted Cum

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)2 $14.90 F&D ($/boe) $2.90 Recycle Ratio 4.3x Breakeven (fixed WTI) $0.85/GJ Payout (months) 15

Choking initial production has no material impact to cumulative production at 365 days

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

• 1.0

2.0 3.0 4.0 5.0 6.0 7.0 8.0 9.0 10.0

2012 (4 wells) 2013 (6 wells) 2014 (8 wells) 2015 (15 wells) 2016 (7 wells)

EUR (Bcf)

Results demonstrate operational success

• Average EUR >9.0 Bcf on most recent 24 Hz wells
• Increased number of stages
• Well placement optimized
• Continuous review of emerging technologies &
• ptimization of wellbore design to lower costs and

enhance recoveries

Continuous program drives lower costs

• Improved operational efficiencies associated with

a continuous program and pad drilling

• Cost reductions from installed water infrastructure
• Completions timed to minimize costs and fill

infrastructure

• Longest well to date rig released in December

Drilling adds: 17,500 boe/d/rig annually

• Continuous one-rig program
• 20 Hz wells/rig/year
• F&D cost <$3/boe2
• Capital efficiency <$6,000/boe/d2

Continuous Improvement in Well Deliverability

Piloting Development

Average EUR/Well1 Decreasing Costs on Multi-well Pads

$4.1 MM $4.6 MM $6.4 MM

• 1. EUR/Well excludes Carmel Bay acquired wells
• 2. Based on IP 365 of 875 boe/d (half-cycle 9.0 Bcf EUR type curve)

$4.5 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

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

Type Curve Supported by Multi-Well Development Pads

• Southern portion of asset base

delineated by multi-well pads

• Established inventory of >450 top-tier

locations

• Minimal maintenance capital:
• $35 MM holds production flat at

15,000 boe/d annually

c-7-H 5 well pad completed Q4/2014 b-22-C 7 well pad completed Q4/15 a-54-D 8 well pad completed Q3/15 b-19-E 3 well pad completed 2015 & 2016

10.5 Bcf 9.0 Bcf 7.5 Bcf

10 km

Upper Montney Multi-Well Pad Performance: Average Rate Per Well

92-C 6 well pad completed Q3/16

Pad Wells Avg D&C ($MM) Avg EUR (Bcf) c-7-H 5 6.4 7.21 a-54-D 8 4.6 8.4 b-22-C 7 4.1 10.31 a-92-C 6 3.9 9.7 b-19-E 3 3.72 9.7

• 1. Pads incl. one Lower Montney pilot well not incl. in avg EUR
• 2. Avg cost for two 2016 wells, 2015well cost $9 MM D&C

7

Infrastructure Investment Strategy

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: $90 MM

10” sales gas line; connects to Spectra 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

• 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

8

Low Cost Future Growth: Owned & Operated Gas Plant

Phase 1 capacity: 10,000 boe/d

• Plant optimized for above average C5+ yield from

22-C pad and to maximize netbacks:

• Condensate/C5+ yield: 30 bbl/MMcf
• C3/C4 yield: 10 bbl/MMcf
• Gas heat content: 1,165 MMbtu/mcf
• Capable of increasing C3/C4 yield to 20 bbl/MMcf

Cost structure reflects ownership advantage

• Operating costs <$3.00/boe
• Plant volumes deliver field netbacks >$13/boe in Q3
• Strong netbacks enhanced by liquids production
• Produced water recycled for ongoing operations

$0.00 $4.00 $8.00 $12.00 $16.00 $20.00 Costs Revenues

$/boe

North Aitken Gas Plant Q3 2016 Operating Netback

Royalties Transportation Operating Costs LPG Condensate Gas

Field netback $13.40/boe 20 40 60 80 100 120 10 20 30 40 50 60

Jan-16 Feb-16 Mar-16 Apr-16 May-16 Jun-16 Jul-16 Aug-16 Sep-16 Oct-16 Nov-16

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)

9 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 Production

Actuals (Gas) Actuals (Liquids)

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

Corporate production at record rates

• Dec 2016: 16,500 boe/d (16% liquids)
• Q4/16: 14,600 boe/d (16% liquids)
• Currently flowing at >16,000 boe/d and capable of

sustaining this rate absent of third party restrictions

• Wells drilled in 2016 maintain budget production of

14,500 boe/d ahead of the plant expansion Production outlook

• Drilling activity in 2017 focused on next stage of

growth

• Production expected to exceed 25,000 boe/d with

commissioning of North Aitken plant expansion in 2017 Cost structure

• Operating costs trending lower as more production

flows through Black Swan facilities

• G&A per boe expected to decrease with current

team able to support increased production levels

Forecast

• n-stream

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

$0.00 $4.00 $8.00 $12.00 $16.00 $20.00 Costs Revenues Q3 2016 $/boe

Q3 2016 Revenues vs. Costs

Interest Royalty G&A Transportation Operating Cost Hedging Processing Income C3/C4 Revenue C5+ Revenue Gas Revenue Cash flow netback $10.91/boe

10

Uniquely Positioned With Multiple Egress Opportunities

Current

Processing

• 110 MMcf/d owned & operated gas plant
• Phase 1: 50 MMcf/d (Jan 2016)
• Phase 2: 60 MMcf/d (2017 expansion)
• 25 MMcf/d firm processing at McMahon

Egress

• Access to service on Alliance, Spectra T-North and TCPL

Future

More than 4 Bcf/d expansion/new projects to enhance market access from Aitken

• Aitken East pipeline (0.5 Bcf/d+)
• TransCanada North Montney Extension (2.4 Bcf/d)
• TransCanada (NGTL) and Spectra expansions (1.3 Bcf/d)
• Increased offload from Spectra to NGTL

Liquids Pipeline Proposals

• Pembina: 75,000 bbl/d pipeline to Taylor connecting to existing

Pembina pipeline system (2017 on-stream)

• Other third party mid-streamer proposals pending but not

formally announced

Firm Capacity (MMcf/d) Plant Pipeline Route Delivery 2017 2018+

North Aitken Creek T-North Station 2 or NGTL 60.0 120.0 McMahon T-North Station 2 or NGTL 6.8 26.8 McMahon Alliance Chicago 9.1

McMahon Gas Plant Sunset T-South to Huntington/Sumas Station 2 Aitken East Pipeline to AECO Aitken Creek Gas Storage TransCanada North Aitken Gas Plant

New/expanded Aitken egress capacity 1.Aitken East pipeline to NGTL 2.Planned North Montney extension 3.Spectra expansions

2 1 3 BRITISH COLUMBIA ALBERTA Beatton River

25 km

11

Leveraging Infrastructure to Access Diverse Markets

TransCanada (NGTL) Spectra

PNW LNG LNG Canada

AECO

Stn 2 Sumas

VANCOUVER EDMONTON

MONTNEY

Kingsgate

BRITISH COLUMBIA ALBERTA

CALGARY

Woodfibre LNG AB oil sands 1.5 - 2 Bcf/d demand 6.0 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

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 being advanced
• 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

Prince Rupert Pipeline Coastal Gaslink

12

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

Aitken Area

DSUs (Acres) 120 (84,000) Liquids Content 35-50 bbl/MMcf (~50% C5+) Pressure Gradient 0.55-0.70 psi/ft Upper Montney Type curve 7.5-9.0 Bcf Raw Gas Upper Montney Hz Locations 480 Lower Montney Type curve 4.6 Bcf Raw Gas Lower Montney Hz Locations 480

Derisked Upper Montney inventory

• Aitken area has been proven across a broad land base
• Five year growth
• Capable of achieving 100,000 boe/d within five

years then flat for 10 years

Significant inventory provides further upside

• Development of remaining Black Swan acreage phased

in once Aitken is established as a production centre

• Competitor activity continues to derisk northern

acreage

c-7-H (pad) Avg EUR = 7 Bcf a-92-C (pad) EUR = 10 Bcf b-19-E (pad)

• Avg. EUR = 10 Bcf

a-54-D (pad) Avg EUR = 8 Bcf b-95-E (well) EUR = 7 Bcf b-22-C (pad) Avg EUR = 10 Bcf c-45-D (well) EUR = 11 Bcf

8 km

Legend

13

Source Water Secured for Development Plan

Beatton River water license

• Water license supports:
• Peak drilling rate of 100+ Hz wells/year
• Development profile capable of achieving

100,000 boe/d in five years

• The first oil & gas industry license issued

under the new BC Water Sustainability Act (Feb 29, 2016)

• Over two years to complete hydrodynamics

and impact assessments in conjunction with OGC & stakeholders

• License valid until Dec 31, 20211

Responsible management & recycling

• Black Swan has constructed over 1.5 MMbbl
• f fresh water storage capacity to manage

seasonal draws

• Produced water is recovered and recycled
• Water handling infrastructure is temporary by

design to allow flexibility of operation and

• ptimization of capital at current stage of

development

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

14

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 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)

15 100 200 300 400 500 600 700 800 Progress Black Swan CNQ Saguaro TOU CR ARX SU SRX ECA CKE UGR Canbriam PPY RDS LXE TODD/POU COP KEL PGF MUR Net DSUs2

Dominant Position in Over-Pressured, Liquids-Rich Fairway

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

Over-pressured

• Highly over-pressured reservoir 13-16 kPa/m

Liquids-rich

• Total liquids of 35-50 bbl/MMcf1 (>50% C5+); maximizes

condensate without crossing into the oil window where well performance is reduced

Low cost

• Shallow target, surface access, drilling characteristics and

contiguous nature of position

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

Black Swan holds the second largest liquids-rich position in the NEBC Montney fairway

25 km

Dry gas Oil Liquids-rich gas

Upper Montney Over-Pressured Liquids-Rich Fairway

16

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

Current Activity

• Pad development: one-rig Montney program drilling up to 20 wells/year
• North Aitken Gas Plant expansion to 110 MMcf/d

One to Three Year Window

• Leverage asset scale to secure long-term firm egress
• Accelerate development

Ongoing

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

17

Appendix

18

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 – Manager, 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 Board Members

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

Black Swan Energy Management and Directors

19

Historical Financial Summary

2016 2015 2015 2014 2014 Q31 Q2 Q1 Full Year Q4 Q3 Q2 Q1 Full Year Q4 Q3 Q2 Q1 Production Oil (bbl/d)

• 65

79 54 64 82 116 17 69

• Gas (mcf/d)

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) 2,506 2,399 1,232 614 875 539 519 521 442 496 483 448 339 Total (boe/d) 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 $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 $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 $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) $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) $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 $68,258 $65,180 $60,538 $0 $0 $555 $50,000 $25,000 $0 $0 $0 $0 $0 Total Net Debt $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 $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 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) 0.44 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 (1.13) (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 (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 (2.28) (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 12.34 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 (1.12) (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 0.38 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 (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 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

• 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

20 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

21

NEBC Growth in 2017 Driven by Junior/Intermediate Producers

Industry investment accelerating

• North Montney production of 1.3 Bcf/d at October 2016
• Activity increasing in 2017 with 12 rigs running in January

Note: Competitor land positions based on public reports and geoSCOUT

200 400 600 800 1,000 1,200 1,400 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

Ave Calender Day Gas (MMcf/d) Production Month

North Montney Production1

Conoco ARC Suncor Kelt CNRL Todd Chinook Tourmaline UGR Saguaro Storm BSE Painted Pony Canbriam Progress

• 1. Historical Tourmaline production represents Shell prior to the Gundy acquisition

22 $0 $2 $4 $6 $8 $1 $1 $0.00 $2.00 $4.00 $6.00 $8.00 $10.00 $12.00 PPY BIR BSE CQE AAV SRX CR ARX PEY TOU NVA VII $/boe

3-Yr P+P FD&A (incl. FDC)

Low Cost Reserves Underpin Growth Plan

• 1. GLJ January 1, 2016 price forecast, includes 2P FDC $1.9 B

Delivered 250% Y/Y increase in 1P reserves & 78% Y/Y increase in 2P reserves

2015 Company Interest Reserves Net Present Value1 Before Income Taxes ($MM) Gas (MMcf) NGLs (mbbl) Total (mboe)2 0% 8% 10% 15% Proved producing 138,536 5,405 28,495 474 286 259 211 Proved non-producing & Proved undeveloped 481,748 18,667 98,957 1,502 575 465 281 Total proved 620,284 24,072 127,453 1,976 861 725 493 Probable 1,246,081 48,025 255,704 5,129 1,325 1,003 524 1,866,365 72,097 383,157 7,105 2,186 1,727 1,017 Proved + probable

96 103 54 104

2015 Booked Montney Locations (357) Proved Upper Probable Upper Proved Lower Probable Lower

Average: $7.97/boe

DSUs Base Case2 Upside Estimate3 # 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

• 2. Five wells/DSU/layer (300 m spacing), two layers developed, ranging from 4.6-7.5 Bcf/well, 90% land utilization
• 3. 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

Internal Estimate of Resource

23

Proved plus probable reserves

• 2015 YE Proved + Probable (2P) reserves were 383 MMboe, of which

68% 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

• 2015 well results averaged greater than 9 Bcf

Infill locations & PUD wells

• GLJ reserves for infill locations assume four wells/layer/DSU and are

based on regional performance and OGIP considerations, the PDP component is typically 75 – 80% of the 2P estimate

• GLJ infill type curve assumptions:
• Upper Montney: 7.5 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, 2015 price forecast
• GLJ has booked approximately 50% of what Black Swan considers the

core development area

Reserve Booking Methodology

Core Development Area

Upper Montney Reserve Booking Map

10 km

24

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

25

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

• 2016 corporate avg: 31 bbl/MMcf (73% C5+)
• Production flowing to McMahon has lower

liquids recoveries averaging 19 bbl/MMcf (73% C5+); 11% liquids

• Production through Black Swan’s North Aitken

gas plant has averaged 40 bbl/MMcf in 2016 (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

• ptimize netbacks
• 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 35-50 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

26

Upper Montney Multi-Well Pad Production Summary

EURs continue to trend upwards 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 Nov/16 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 19-E Well Pad b-B19-E 200/b-097-D 094-H-04/00 2016 Upper tested 9.5 a-A20-E 200/c-088-D 094-H-04/00 2016 Upper tested 9.1 b-19-E 200/b-098-D 094-H-04/02 2015 Upper 5,701 5,129 4,617 1.7 10.0 92-C Well Pad a-B92-C 200/c-004-F 094-H-04/00 2016 Upper tested 10.1 a-A92-C 200/a-014-F 094-H-04/00 2016 Upper tested 11.6 a-E92-C 200/b-080-B 094-H-04/00 2016 Upper tested 8.3 a-D92-C 200/a-080-B 094-H-04/00 2016 Upper tested 8.6 a-C92-C 200/d-080-B 094-H-04/00 2016 Upper tested 8.7 a-92-C 200/d-004-F 094-H-04/02 2013 Upper tested 10.5 22-C Well Pad b-G22-C 202/b-010-B 094-H-04/00 2015 Upper 7,343 6,450 NA 1.2 10.0 b-F22-C 200/d-010-B 094-H-04/00 2015 Upper 5,790 6,375 NA 1.3 10.5 b-E22-C 202/c-034-C 094-H-04/00 2015 Upper 7,886 7,001 NA 1.2 11.0 b-D22-C 200/c-034-C 094-H-04/00 2015 Upper 6,656 6,454 NA 1.2 11.0 b-C22-C 200/a-044-C 094-H-04/00 2015 Upper 6,522 5,783 NA 0.6 10.3 b-A22-C 200/c-010-B 094-H-04/02 2013 Upper 6,521 5,900 NA 1.1 9.0 54-D Well Pad a-D54-D 200/a-075-D 094-H-04/00 2015 Upper 4,428 4,431 NA 1.1 8.6 b-B54-D 200/b-075-D 094-H-04/00 2015 Upper 4,659 4,587 NA 1.1 7.5 a-C54-D 202/d-066-D 094-H-04/00 2015 Upper 4,520 4,271 NA 1.1 8.1 a-B54-D 200/d-066-D 094-H-04/00 2015 Upper 5,065 4,602 NA 1.0 8.1 a-A54-D 202/a-032-D 094-H-04/00 2015 Upper 6,893 6,042 NA 1.4 8.6 a-54-D 200/a-032-D 094-H-04/00 2015 Upper 3,913 4,201 NA 0.9 8.6 b-A54-D 202/a-033-D 094-H-04/00 2015 Upper 5,368 4,949 NA 0.0 8.1 b-54-D 200/a-033-D 094-H-04/00 2015 Upper 5,284 5,080 NA 0.9 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 1.5 7.5 c-A7-H 202/a-096-A 094-G-01/00 2014 Upper 4,870 4,274 2,738 1.3 6.0 c-7-H 200/b-096-A 094-G-01/00 2014 Upper 7,506 4,559 3,171 1.4 6.0 b-17-H 200/a-095-A 094-G-01/00 2014 Upper 10,792 6,823 4,441 2.2 9.8

27

Update on Recent Results

19-E

• ffsets to existing Hz

completed 2015 & 2016

• 1. Completed well acquired from Carmel Bay
• 2. Well drilled & completed by Black Swan, on-stream 2015
• 3. At -37C plant temperature

92-C 6 well pad completed Q3/16

92-C well pad

• Five Upper Montney wells completed Q3/16
• Average EUR >9.0 Bcf indicated on test
• Liquids yields higher than type curve:
• 20-25 bbl/MMcf lease condensate
• 10 bbl/MMcf plant C5
• 20 bbl/MMcf C3/C43
• Completed two 30 stage wells, vs. 20 stages on

standard design, yielding positive results

• First well on-stream Oct 30, remaining wells backfill

declines & maintain plant at capacity to mid-2017

19-E well pad

• Two Upper Montney wells completed Q3/16,
• ffsetting an existing Hz producer
• Average EUR >9.0 Bcf indicated on test
• Original b-19-E well cleaned up and continues to

deliver strong production post completion of the

• ffsetting wells
• Production from new wells sufficient to fill firm

commitment at McMahon through 2017

Final Flow Test Stages 2016 D&C Cost Gas Rate Casing Pressure Expected EUR # ($MM) (mcf/d) (kPa) (Bcf) 92-C Well Pad a-92-C1 32 13,310 10,600 10.5 a-A92-C 30 4.1 8,873 15,000 11.6 a-B92-C 30 4.1 8,696 13,300 10.1 a-C92-C 20 3.8 7,809 11,000 8.7 a-D92-C 20 3.8 7,809 10,750 8.6 a-E92-C 20 3.8 8,341 9,300 8.3 19-E Well Pad (Upper Montney) b-B19-E 22 3.7 9,200 14,000 9.5 a-A20-E 30 3.7 8,300 12,500 9.1 b-19-E2 20 10.0

28

2017 Capital Program: Growth to 25,000 boe/d

c-2-C 6 well pad a-32-C 6 well pad a-72-C 8 well pad d-42-D 8 well pad Black Swan North Aitken Phase 2: Field work commenced in Q4/16 Expected on-stream Q2/17 Full capacity Phase 1 & 2

Expanding the capital program

• 2017 capital budget: $180 MM
• DCET activity:
• 19 Hz wells drilled
• 16 Hz wells completed
• 16 Hz wells tied-in
• Plan to test longer lateral lengths,

higher proppant intensity and tighter stage spacing

• Production expected to increase to

>25,000 boe/d once Phase 2 of the North Aitken Creek gas plant is at full capacity

• Additional capital included to expand

Black Swan’s gathering system and

• rder long lead equipment for Plant 2

(planned on-stream Q4 2018)

29

0% 10% 20% 30% 40% 50% 60% 70% Bakken Tier 1 Eagle Ford Condensate Tier 1 Midland Lower Spraberry TFS Tier 1 Delaware Bone Spring Black Swan Montney (9.0 Bcf) Delaware Avalon Delaware Wolfcamp (South) Eagle Ford Oil Tier 1 Niobrara Tier 1 Delaware Wolfcamp (North) Eagle Ford Wet Gas Midland Wolfcamp Tier 1 Marcellus Dry Tier 1 Black Swan Montney (7.5 Bcf) Cleveland Core New Mexico Shelf Haynesville Tier 1 Midland Wolfcamp Tier 2 Utica Wet Tier 1 STACK (Meramec Oil) Niobrara Tier 2 Eagle Ford Oil Tier 2 Cana Tier 1 San Juan Oil Marcellus Dry Tier 2 Bakken Tier 2 Eagle Ford Condensate Tier 2 Utica Dry Marcellus Wet Pinedale TFS Tier 2 Fayetteville Haynesville Tier 2 Piceance Utica Condensate Barnett Cana Tier 2 Granite Wash Utica Wet Tier 2

After Tax IRR (%)

Resource Play Benchmarking at US$50/bbl WTI & US$3.25/mcf NYMEX (half-cycle)

Comparative Ranking Among Top US Plays

Source: Tudor Pickering Holt & Co. and Black Swan Energy

Black Swan well results improved over last two years based on operational enhancements & geotechnical work

• 1. Half-cycle economics for US plays assumes 40% NGL realization, 35% corporate tax burden and 20% royalty
• 2. Black Swan economics reflect US$3.25 NYMEX pricing which assumes C$3.00/GJ AECO, US$1.30/C$ and US$0.80/MMBtu differential
• 3. For comparative purposes Black Swan economics shown reflect a 35% corporate tax rate (dark red) and 26% corporate tax rate based on Canadian corporate tax rates, however

with over C$800 MM of tax pools at YE 2015 the company does not expect to be taxable over the foreseeable future, liquids are modelled relative to WTI: C5+: 102%, C4: 50%, C3: 35%, average royalty rate over the life of the well is 12% at illustrated price levels

IRR at comparative US corporate tax rate IRR at Canadian corporate tax rate

30

Completions – Evolution of Design Concepts is Ongoing

Initial Completions Design Current Completions Design Continuous Evolution of Ideas Perf and plug (cemented liners)

• 1,700 m lateral
• 8-10 stages, 3-5 clusters/stage
• 150-225 m stage spacing (50-75 m

perf spacing)

• Proppant: 150-200 tonne/stage, 1,200

tonne/well

Operational and technical Issues

• Down time between fracs to set plugs

and perforate

• Drilling out plugs post-frac
• Potential for uneven frac distribution
• Potential for inefficient drainage

Open hole ball drop

• 1,750 m lateral
• 20 stages, single port entry
• 85 m port spacing
• Proppant: 90 tonne/stage, 1,800 tonne/well
• 1.1 tonne/m loading
• 10,500 m3 recycled slickwater blend

Pad design modifications provide

• Optimized landing interval for frac initiation
• Multiple wells, modified zipper frac
• Complementary inter-well stage overlap
• Maximum interference between wells/stages
• Increased sand loading
• Enhanced reservoir access

Optimizing Per DSU Recovery

• Extended reach wells to reduce capital per DSU
• Tighter stage spacing (60m vs 90m)
• Increased sand intensity with wider inter-well

spacing

• Fluid additive technology
• Diversion techniques
• Unlimited stage fracturing systems (NCS, Stage

Completions)

• Improvements in drilling technologies

31

Drilling Curves Show Efficient Operations

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 2 4 6 8 10 12 14 16 18 20 Depth (meters MD) Total Days

Total Time vs. Depth

D-42-D Four Wells A-92-C Five Wells B-22-C Five Wells

• 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
• Variation in build section performance as a

result of range of compressive strengths over acreage

• On average wells are drilled and cased with

pad rig in under two weeks; 20 wells/rig/yr

• Average drilling costs $1.8 MM per well
• Continuous improvement of fluid selection

and properties, bit selection, BHA design, rig design

Surface hole Set casing, cement Vt section Build section (turn to Hz) Change to Hz drilling assembly Hz section Set packers, cement, rig out Preset Rig Pad Rig Move pad rig, install BOP

32

Over 4 Bcf/d New Egress Planned Within Three Years

McMahon Sunset T-South to Huntington/Sumas Station 2 Aitken East Pipeline to AECO Aitken Creek Gas Storage TransCanada 16 km

Black Swan is evaluating multiple

• ptions to increase egress to

diverse markets in the context of estimated long term tolls and expected on-stream dates

Source: Company reports and Black Swan Energy *North Montney increase to 2.4 Bcf/d assumes the PETRONAS PNW LNG moves to positive FID

2017 2018 2019 Receipt Point Delivery Point Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 Spectra High Pine

• Ft. Nelson T-North

TransCanada Sunset 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 Wyndwood

• Ft. St. John T-North

TransCanada Sunset or Station 2 50 50 50 50 50 50 50 50 Spruce Ridge Program Aitken Creek TransCanada Sunset or Station 2 402 402 402 402 402 Total Spectra 240 240 428 428 428 830 830 830 830 830 TransCanada Towerbirch Tower Lake or Sunset TransCanada NGTL 859 859 859 859 859 859 859 859 859 North Montney Aitken Creek (Phase 1), Kahta (Phase 2) TransCanada NGTL or PNW LNG 1,000 1,000 1,000 1,000 1,400 1,400 1,400 1,400 1,400 1,400 2,400 Total TransCanada 1,000 1,000 1,859 1,859 2,259 2,259 2,259 2,259 2,259 2,259 3,259 Producer Led Aitken East Aitken Creek TransCanada NGTL 500 500 500 500 Cumulative Total 1,000 1,240 2,099 2,287 2,687 2,687 3,089 3,589 3,589 3,589 4,589

33

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 firm capacity on T-North Q1 2018 to Q4 2029

From North Aitken Creek BSE Plant

• 40 MMcf/d firm capacity on T-North Q4 2015 to Q4 2028
• 20 MMcf/d firm capacity on T-North Q3 2017 to Q2 2028
• 60 MMcf/d firm capacity on T-North Q4 2018 to Q4 2033

Risk management positions (Jan 12, 2017)

• Black Swan utilizes financial and physical contracts to manage price volatility in the context of internal hedging policy guidelines

Natural Gas Liquids AECO Swaps Station 2 Differential AECO Costless Collars 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 (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 Q1 2017 26,660 $2.82 47,344 ($0.42) 16,828 $2.78 $3.23 6,192 $4.08 800 $63.98 100 $60.00 $75.00 Q2 2017 29,331 $2.80 23,330 ($0.50) 10,000 $2.85 $3.21 6,845 $4.17 800 $63.98 100 $60.00 $75.00 Q3 2017 26,633 $2.81 20,337 ($0.52) 10,000 $2.85 $3.21 6,845 $4.17 800 $63.98 100 $60.00 $75.00 Q4 2017 26,626 $2.80 23,641 ($0.50) 10,000 $2.85 $3.21 2,306 $4.17 800 $63.98 100 $60.00 $75.00 Q1 2018 21,410 $2.81 20,656 ($0.54) 323 $71.68 Q2 2018 20,971 $2.81 19,330 ($0.55) 313 $71.75 Q3 2018 20,590 $2.81 18,337 ($0.56) 303 $71.83 Q4 2018 20,260 $2.81 17,337 ($0.57) 300 $71.85 Q1 2019 12,488 $2.85 16,344 ($0.35) 150 $70.95 Q2 2019 1,597 $2.86 16,000 ($0.36) 127 $70.97 Q3 2019 16,000 ($0.38) Q4 2019 10,609 ($0.37) 2017 27,311 $2.81 28,575 ($0.48) 11,684 $2.83 $3.21 5,540 $4.14 800 $63.98 100 $60.00 $75.00 2018 20,804 $2.81 18,904 ($0.56) 310 $71.78 $0.00 $0.00 2019 3,477 $2.86 14,726 ($0.37) 102 $70.98 $0.00 $0.00

34

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