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Corporate PresentationNovember 2017
2
Black Swan Overview
FT ST JOHN
EDMONTON
MONTNEY FAIRWAY
ALBERTA
10 km
NEBC liquids‐rich Montney
Well funded, private equity backed• Azimuth Capital Management• CPPIB• Warburg Pincus
3
North Montney: Scale, Growth, Value
Material Scalable Position
• 341 net sections of Montney rights2 (100% working interest)• 71 Hz wells drilled by YE 2017• Inventory of over 2,500 Hz locations
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
• Returns: 35% full‐cycle & 80% half‐cycle at $2.50/GJ AECO1
• Average 9 Bcf EUR last 49 Hz Upper Montney wells • 2017 well costs $4.7 MM D&C• Liquids yield 30‐50 bbl/MMcf
Infrastructure Advantage
• Owned & operated infrastructure• Operating cost <$2.50/boe through operated gas plant• Flexible pace of development
Strong Balance Sheet
• $850 MM equity raised to date3• $250 MM syndicated bank line4 ($200 MM undrawn)• 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 DCET2. 312 net DSUs where one DSU = 700 acres 3. $800 MM drawn, $50 MM undrawn at Sept 30, 20174. Includes a $50 MM accordion for additional syndicate participation; $49 MM drawn at Sept 30, 20175. US dollar denominated, matures Jan 2024, 9% coupon
4
‐
4,000
8,000
12,000
16,000
20,000
24,000
28,000Q1
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 Produ
ction (boe
/d)
Building Momentum with Scale Exiting 2017
Corporate production• Dec 2016: 16,650 boe/d (16% liquids)• Q3 2017: 17,800 boe/d (20% liquids)• Q4 2017E: 24,000 – 26,000 boe/d (20% liquids)
Reserves growth1
• Significant increases in both 1P and 2P reserves Y/Y• 2016 YE: 2P 478 MMboe; 1P 171 MMboe• 2016 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)
Production Growth
Delineation
‐ 50
100 150 200 250 300 350 400 450 500
2012 2013 2014 2015 2016
Reserves (M
Mbo
e)
PDP PDNP + PUD Probable
Reserve Growth
Running less than one rig annually delivered: 60% CAGR Q4 2014‐2018
Development
5
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 20 bbl C3/C4
0%
20%
40%
60%
80%
100%
120%
140%
160%
180%
$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
Half Cycle ‐ 7.5 Bcf (8.6 Bcfe)Half Cycle ‐ 9.0 Bcf (11 Bcfe)Half Cycle ‐ 10.5 Bcf (13 Bcfe)
0%
10%
20%
30%
40%
50%
60%
70%
80%
$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 Full Cycle Economics1
Full Cycle ‐ 7.5 Bcf (8.6 Bcfe)Full Cycle ‐ 9.0 Bcf (11 Bcfe)Full Cycle ‐ 10.5 Bcf (13 Bcfe)
Half Cycle 9.0 Bcf Wells Breakeven:US$50/bbl WTI: ~$0.80/GJ AECO
Full Cycle 9.0 Bcf Wells Breakeven:US$50/bbl WTI: ~$1.40/GJ AECO
62%29%
9%
Gas
C5+
C3/C4
AssumptionsD&C Cost ($MM, excl. $0.4 MM tie‐in) $4.6EUR (Bcf) 9.0
IP30 ‐ Total (boe/d) 1,300Heat Content (MMBtu/mcf) 1,150Liquids Yield (bbl/MMcf) 40Royalty Drilling Credit ($ MM) $1.05 Opex & Transportation ($/boe) $4.05 Full Cycle – Infrastructure ($/boe) $1.30Full Cycle – G&A ($/boe) $0.90
9 Bcf Well Half Cycle: $2.50/GJ & US$50/bblB‐tax NPV ($MM) $7.5B‐tax IRR 80%F&D ($/boe) $2.90Payout (months) 14
Revenue Enhanced by LiquidsHalf‐cycle Revenue Mix at 40 bbl/MMcf4
6
$0.0
$1.0
$2.0
$3.0
$4.0
$5.0
$6.0
$7.0
2014 2015 2016 2017E
D&C Co
sts ($M
M/w
ell)
Drilling Cost Completion Cost Design Evolution
Repeatable Well Deliverability at Low Cost
Decreasing Costs on Multi‐well Pads
$4.7 MM2
1. Well results are not normalized for completions2. 2017 costs includes $0.5 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
0.0
2.0
4.0
6.0
8.0
10.0
12.0
14.0
EUR (Bcf/w
ell)
Upper Montney Wells (by completion date)
EUR (on‐stream) EUR (tested) Average EUR
2012/13 2014 2015 2016 2017
Ongoing operational success• Avg EUR: 9.0 Bcf since 2012 (49 wells)1• 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)
7
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
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
10.5 Bcf9.0 Bcf7.5 Bcf
Type Curves
Core area delineated with high rate pads
8
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”6”
6”6”
10”10”
10”10”
Gathering trunk‐lines built H1/16
10”10”
8”8”
10 km
Existing gathering trunk‐lines
100% Owned & operated infrastructure
Plant 1: 110 MMcf/d North Aitken Creek Gas Plant • Phase 1: 50 MMcf/d (Q1 2016)• Phase 2: 60 MMcf/d (Q2 2017)1
• 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 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)
1. Full capacity reached Nov 2017
9
Owned and Operated Infrastructure: Superior Netback
Oct/17 capacity: 85 MMcf/d (16,000 boe/d)• Final compression on‐stream November 2017• 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
Top tier operating costs• Opex trending <$2.50/boe in 2017• Liquids yields enhance revenues• Plant operating netbacks >$16.50/boe1
• Produced water recycled$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
$/bo
e
North Aitken Gas Plant H1 2017 Operating Netback
RoyaltyTransportationOperating CostC3/C4 RevenueC5+ RevenueGas Revenue
Field netback $16.76/boe
1. Based on annual pricing of $2.29/GJ AECO, ‐$0.43/GJ Station 2 to AECO differential, US$50/bbl WTI and $1.30 C$/US$
0
10
20
30
40
50
60
70
80
90
100
0
20
40
60
80
100
120
Jan/16 May/16 Sep/16 Jan/17 May/17 Sep/17
Liqu
ids Y
ield (b
bl/m
mcf)
Gas Produ
ction (M
Mcf/d)
North Aitken Creek Gas Plant Production
Inlet Gas (MMcf/d) Inlet Capacity (MMcf/d)C5+ Yield (bbl/MMcf) C3/C4 Yield (bbl/MMcf)
Production shut‐in to facilitate offsetting completions of new pads
Downtime for expansion and turnaround
10
Capital Program Drives Transition to Low Cost Structure
2017 production at record rates• Production of 17,800 boe/d in Q3• 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%
20%
40%
60%
80%
100%
$0.00
$1.00
$2.00
$3.00
$4.00
$5.00
$6.00
$7.00
$8.00
Jan‐16 Apr‐16 Jul‐16 Oct‐16 Jan‐17 Apr‐17 Jul‐17 Oct‐17 Jan‐18 Apr‐18 Jul‐18 Oct‐18
Prod
uctio
n to M
cMah
on
$/bo
e
Corporate Operating Costs
Opex (Excl. Transport) % Production to McMahon
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 Apr‐18 Jul‐18 Oct‐18
Daily Produ
ction (boe
/d)
Black Swan Production
Actuals (Gas) Actuals (Liquids) Base Decline Completed Awaiting Capacity 2018 Completions
on‐stream
2017 completions
Final compressor commissioned at North Aitken Phase 2 2018
completions
Forecast
11
$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
$/bo
e
2017E Revenues vs. CostsInterest
Royalty
G&A
Transportation
Operating Cost
Hedging
Processing Income
C3/C4 Revenue
C5+ Revenue
Gas Revenue
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)
North Aitken Plant
10 km
21%
22%
5%
48%
4%
2017 Capital Program
DrillingCompletionsWellhead tie‐inGathering & facilitiesOther
Capital program• 2017 budget: $180 MM• 19 Hz wells drilled, 16 completed, 16 tied in• 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 (20% liquids)
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$
32‐C Pad(6 wells)
Field netback $10.86/boe
12
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 Bcf over last 49 Upper Montney 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
$MM
Free Cash Flow Generation at 26,000 boe/d1
Maintenance Capital Free Cash Flow Total Cash Flow
13
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)
92‐C padEUR = 9 Bcf
54‐D padAvg EUR = 9 Bcf
22‐C padAvg EUR = 11 Bcf
19‐E padAvg. EUR = 9 Bcf
7‐H padAvg EUR = 7 Bcf
45‐D wellEUR = 11 Bcf
14
Connecting to Multiple Markets
McMahon Gas Plant
Sunset
T‐South to Huntington/Sumas
Station 2
Aitken Creek Gas Storage
NGTL to AECO
North Aitken Gas Plant
BRITISH COLU
MBIA
ALBE
RTA
25 km
1. NGTL is part of the TransCanada pipeline system2. North Montney Mainline subject to regulatory approval
Egress via three major natural gas pipelines• Enbridge
• Delivery to Station 2 or Sumas• Interconnection to the NGTL1 system (AECO) & Alliance
• Alliance• Deliver to ATP or Chicago
• TransCanada• North Montney Mainline2 (1.5 Bcf/d) planned Q2/19• Deliver to AECO
• Able to flow to multiple markets across North America
15
Egress Commitments Provide Transformational Growth
1. NGTL is part of the TransCanada pipeline system2. TCPL 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; $1.8 MM/month with no new processing capacity
Full cycle economics underpinned by owned & operated infrastructure• New processing units will be built in 100 MMcf/d (19,000 boe/d) increments
• Plant construction will be timed to align with pipeline expansion
Egress capacity grows to 392 MMcf/d• Service on all three Canadian gas transmission systems2
• Option to flow up to 100% on TCPL by 2019• Long term, more than 2/3 of egress on TCPL with access to AECO and beyond
Surplus capacity provides optionality• Connection to different markets enables decisions to maximize netbacks
• Option to accelerate production growth based on market conditions
Option to accelerate
0
50
100
150
200
250
300
350
400
Oct
Dec
Feb
Apr
Jun
Aug
Oct
Dec
Feb
Apr
Jun
Aug
Oct
Dec
Feb
Apr
Jun
Aug
Oct
Dec
Feb
Apr
Jun
Aug
Oct
Dec
2018E 2019E 2020E 2021E
Gas (M
Mcf/d)
Planned Plant Capacity vs. Egress Commitments
Existing Processing
Plant 2A
Plant 2B
Alliance Capacity Enbridge Capacity TransCanada Capacity
Option to accelerate
16
Source Water Secured for Development Plan
Beatton River water license• License supports peak drilling rate of 100+ Hz wells/year
• Underpins growth to 100,000 boe/d • Permanent intake and storage in place• License valid until Dec 31, 20211
Responsible management & recycling • Over 2.2 MMbbl of fresh water storage capacity constructed
• Produced water is recovered and recycled• Produced water handling infrastructure is temporary by design to allow flexibility of operation and optimization of capital
Water License Intake 1
Water Pump Station
b‐54‐D65,800 m³
c‐7‐H60,300 m³
Water pump stationWater pump station 1. With renewal provisions
b‐11‐A44,900 m³
10 km
d‐42‐D 65,000 m³
Black Swan has re‐used 100% of produced water since June 2014
a‐72‐C 68,000 m³
c‐38‐C 56,000 m³
17
0
200
400
600
800
1,000
1,200
1,400
1,600
Nov ‐ Dec 2017 2018 2019
Hed
ged Vo
lumes (b
oe/d)
C4 & C5+ Hedging & Average Contract Pricing
Swaps (C$ WTI) Collars (C$ WTI) Puts (C$ WTI)
010,00020,00030,00040,00050,00060,00070,00080,00090,000
Nov ‐ Dec 2017 2018 2019
Hed
ged Vo
lumes (G
J/d)
Natural Gas Hedging & Average Contract Pricing
Station 2 Diff ($/GJ) AECO Swaps ($/GJ)AECO Collars ($/GJ) AECO Puts ($/GJ)Chicago Swaps (C$/MMBtu)
Risk Management & Pricing
• 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
Note: Put prices are shown net of premiums and Chicago prices are shown prior to transportation costs on Alliance
$2.72
‐$0.44
$2.85 x
$3.21
$2.54
‐$0.49
$2.70
$2.57
‐$0.37
$2.76
$65.33
$56.54 x
$67.70
$66.80
$65.72$55.00 x
$67.25$55.00 x
$68.00$61.82
59%
31%
11%
2%
12%
25%
18%42%
0%10%20%30%40%50%60%70%80%90%100%
Nov ‐ Dec 2017 2018
% of C
orpo
rate Produ
ction
2017/2018 Gas Pricing Portfolio
Unhedged Station 2
Unhedged AECO
Unhedged Chicago
Hedged AECO 50% 50%
50% 50%
0%10%20%30%40%50%60%70%80%90%100%
Nov ‐ Dec 2017 2018
% of C
orpo
rate Produ
ction
2017/2018 Liquids (C4 & C5+) Pricing Portfolio
Unhedged
Hedged
18
$0.00
$2.00
$4.00
$6.00
$8.00
$10.00
$12.00
2017
E $/bo
e
Operating Cost (2017E)
$0.0
$2.0
$4.0
$6.0
$8.0
$10.0
$12.0
$14.0
D&C Co
st $MM
Drilling & Completion Cost (2017E)
0%
20%
40%
60%
80%
100%
Gas W
eightin
g
Gas Weighting (H1 2017)
0.0
2.0
4.0
6.0
8.0
10.0
12.0
EUR (Bcf)
EUR ‐Wells Drilled in Last Three Years
Differentiation: Performance on Multiple Factors vs. Peers1
Well performance
Competitive capital costs
Infrastructure advantage
Liquids contribution
Black Swan Full Cycle
Forward Economics3
$/boe
Revenue 20.75Royalty 1.35Opex + transport 5.10G&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
BSE8.9
BSE4.7
BSE4.20
BSE84%
Source: Internal estimates, National Bank Financial, CIBC World Markets & company reports
Includes three Lower Montney wellsBSE Plant (excludes McMahon production)
19
0
100
200
300
400
500
600
700
800
Progress
Black Sw
anCN
QSaguaro
TOU
Polar S
tar
CR ARX
ECA
PPY
SRX SU CKE
Canb
riam
RDS
LXE
Aduro
TODD
/POU
COP
KEL
PGF
MUR
Net DSU
s2
Repeatable deliverability• Highly over‐pressured reservoir 13‐16 kPa/m
Liquids‐rich• Total liquids of 30‐50 bbl/MMcf1 (>50% C5+)
Low capital cost • Shallow target, surface access and drilling characteristics
Low operating costs• Owned & operated infrastructure
Scalable• Large contiguous position
Liquids‐rich gas
Delivering on a Long Term Strategy
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
Alberta
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
20
Appendix:Corporate & Financial Summary
21
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.
22
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 $1 billion.
23
Historical Financial Summary
1. Preliminary values, subject to Audit Committee approval2. NOI as presented does not include realized hedging gains/(losses)
2017 2016 2016 2015 2015 2014 2014
Q31 Q2 Q1 Full Year Q4 Q3 Q2 Q1 Full Year Q4 Q3 Q2 Q1 Full Year Q4 Q3 Q2 Q1
Production
Oil (bbl/d) ‐ ‐ ‐ 16 ‐ ‐ ‐ 65 79 54 64 82 116 17 69 ‐ ‐ ‐
Gas (mcf/d) 85,769 66,194 85,832 67,151 74,626 75,484 71,376 46,944 23,538 26,513 24,318 19,431 23,853 18,220 22,410 21,098 17,185 12,044
NGL (bbl/d) 3,501 1,868 2,427 2,099 2,254 2,506 2,399 1,232 614 875 539 519 521 442 496 483 448 339
Total (boe/d) 17,796 12,900 16,732 13,307 14,692 15,087 14,295 9,121 4,616 5,348 4,656 3,840 4,612 3,496 4,300 3,999 3,312 2,346
Financial ($ 000)
Net Operating Income2 14,130 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
EBITDA 19,631 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 16,347 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) 47,608 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) 23,176 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 48,759 13,091 ‐ 76,555 76,555 68,258 65,180 60,538 ‐ ‐ 555 50,000 25,000 ‐ ‐ ‐ ‐ ‐
Term Notes 121,078 125,645 128,867 ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐
Total Net Debt 193,013 162,916 120,727 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 250,000 200,000 200,000 200,000 200,000 140,000 140,000 130,000 130,000 130,000 80,000 70,000 70,000 40,000 40,000 24,000 24,000 12,000
Netback Summary ($/boe)
Net Revenue 15.49 22.13 23.07 17.97 22.65 18.83 14.97 13.60 18.82 16.26 18.19 21.77 20.02 34.69 26.39 33.43 40.01 44.88
Hedging Gain (Loss) 4.06 0.27 (0.20) 0.87 (1.28) 0.44 2.46 2.60 0.33 0.60 (0.04) 0.60 0.15 ‐ ‐ ‐ ‐ ‐
Royalties (0.65) (1.02) (1.26) (0.94) (1.44) (1.13) (0.46) (0.57) (0.99) (0.73) (0.76) (0.95) (1.57) (3.67) (3.67) (3.33) (3.77) (4.12)
Opex (3.25) (5.74) (4.39) (4.56) (4.01) (3.53) (4.49) (6.34) (9.07) (7.49) (9.24) (8.80) (10.99) (10.77) (8.82) (10.13) (12.24) (13.44)
Transportation (2.96) (3.23) (2.34) (2.10) (2.29) (2.28) (2.19) (2.31) (0.98) (1.77) (0.55) (0.73) (0.72) (0.82) (0.83) (0.88) (0.79) (0.77)
Operating Netback 12.69 12.40 14.83 11.24 13.63 12.34 10.29 6.98 8.11 6.87 7.60 11.89 6.89 19.43 13.07 19.09 23.21 26.55
General & Administrative (0.83) (1.45) (1.27) (1.76) (2.33) (1.12) (1.68) (2.01) (4.52) (5.28) (3.95) (4.57) (4.17) (5.78) (6.80) (3.92) (5.90) (6.94)
Processing Income 0.14 0.19 0.20 0.27 0.19 0.38 0.19 0.37 0.47 1.61 ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐
Interest/Other Expense (2.02) (2.87) (1.91) (0.87) (0.74) (0.70) (1.48) (0.44) (1.16) (0.96) (0.90) (2.75) (0.30) (0.32) (0.23) (0.08) (0.68) (0.40)
Cash Flow From Operations 9.98 8.27 11.85 8.88 10.73 10.91 7.32 4.90 2.90 2.24 2.75 4.57 2.42 13.33 6.04 15.09 16.64 19.21
24
Appendix:Half‐cycle Input Assumptions
25
Type Curve Assumptions
1. Economics assume Black Swan owned infrastructure; FX C/US$ 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 $5 MM3. Black Swan pays BC Crown royalties calculated on a sliding scale for gas based on price and production rate & fixed
percentage of revenue for liquids 4. Pricing relative to C$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
26
Appendix:Drilling, Completions & Well Results
27
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
4,6000 2 4 6 8 10 12 14 16 18 20
Dep
th (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
28
Completions: Optimization of Design
4,600
5,600
6,600
7,600
2012 2013 2014 2015 2016 20171,400
1,600
1,800
2,000
2,200
2,400
2,600
feet
metres
Completed Well Length
330
430
530
630
730
830
930
2012 2013 2014 2015 2016 20170.5
0.7
0.9
1.1
1.3
1.5
lbs/ft
tonn
e/m
Proppant Concentration
0
100
200
300
400
500
600
700
2012 2013 2014 2015 2016 2017020406080100120140160180200220
feet
metres
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
29
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 Aug/17 EUR
Reference (Year) Target (MMcf/d) (MMcf/d) (MMcf/d) (Bcf) (Bcf)9 Bcf Type Curve (unrestricted) 7,000 6,100 4,330 9.09 Bcf Type Curve (choked) 4,400 4,400 3,980 9.02‐C Well Padc‐E2‐C 200/a‐091‐K 094‐A‐13/00 2017 Upper 6,641 5,732 NA 0.4 10.1c‐D2‐C 200/b‐100‐J 094‐A‐13/00 2017 Upper 5,815 5,179 NA 0.4 10.8c‐C2‐C 200/a‐100‐J 094‐A‐13/00 2017 Upper 6,076 NA NA 0.2 10.6c‐B2‐C 200/c‐025‐C 094‐H‐04/00 2017 Upper 5,463 NA NA 0.1 9.2c‐A2‐C 200/b‐035‐C 094‐H‐04/00 2017 Upper 5,178 NA NA 0.3 10.3c‐2‐C 200/a‐035‐C 094‐H‐04/00 2017 Upper 6,810 NA NA 0.4 11.019‐E Well Padb‐B19‐E 200/b‐097‐D 094‐H‐04/00 2016 Upper 3,240 4,444 NA 0.6 9.0a‐20‐E 200/c‐088‐D 094‐H‐04/00 2016 Upper 5,000 4,448 NA 0.8 7.5b‐19‐E 200/b‐098‐D 094‐H‐04/02 2015 Upper 5,701 5,129 4,617 2.5 10.592‐C Well Pada‐B92‐C 200/c‐004‐F 094‐H‐04/00 2016 Upper 5,917 5,577 NA 1.0 10.0a‐A92‐C 200/a‐014‐F 094‐H‐04/00 2016 Upper 6,126 5,614 NA 0.9 10.0a‐E92‐C 200/b‐080‐B 094‐H‐04/00 2016 Upper 4,847 4,309 NA 0.6 7.5a‐D92‐C 200/a‐080‐B 094‐H‐04/00 2016 Upper 4,833 4,317 NA 1.0 8.0a‐C92‐C 200/d‐080‐B 094‐H‐04/00 2016 Upper 3,774 3,519 NA 0.5 7.5a‐92‐C 200/d‐004‐F 094‐H‐04/02 2013 Upper 5,886 5,951 NA 1.4 10.522‐C Well Padb‐G22‐C 202/b‐010‐B 094‐H‐04/00 2015 Upper 7,343 6,450 4,900 1.8 11.0b‐F22‐C 200/d‐010‐B 094‐H‐04/00 2015 Upper 5,790 6,375 5,217 2.2 12.0b‐E22‐C 202/c‐034‐C 094‐H‐04/00 2015 Upper 7,886 7,001 NA 1.6 11.0b‐D22‐C 200/c‐034‐C 094‐H‐04/00 2015 Upper 6,656 6,454 4,995 1.9 11.0b‐C22‐C 200/a‐044‐C 094‐H‐04/00 2015 Upper 6,522 5,783 NA 1.5 10.5b‐A22‐C 200/c‐010‐B 094‐H‐04/02 2013 Upper 6,521 5,900 4,655 1.8 10.054‐D Well Pada‐D54‐D 200/a‐075‐D 094‐H‐04/00 2015 Upper 4,428 4,431 3,697 1.8 9.0b‐B54‐D 200/b‐075‐D 094‐H‐04/00 2015 Upper 4,659 4,587 3,367 1.6 8.0a‐C54‐D 202/d‐066‐D 094‐H‐04/00 2015 Upper 4,520 4,271 3,454 1.6 8.0a‐B54‐D 200/d‐066‐D 094‐H‐04/00 2015 Upper 5,065 4,602 3,336 1.6 7.5a‐A54‐D 202/a‐032‐D 094‐H‐04/00 2015 Upper 6,893 6,042 4,695 2.1 9.0a‐54‐D 200/a‐032‐D 094‐H‐04/00 2015 Upper 3,913 4,201 3,739 1.6 8.5b‐A54‐D 200/b‐032‐D 094‐H‐04/00 2015 Upper 5,368 4,949 3,923 1.7 9.0b‐54‐D 200/a‐033‐D 094‐H‐04/00 2015 Upper 5,284 5,080 3,920 1.7 9.07‐H Well Padc‐B7‐H 200/b‐095‐A 094‐G‐01/02 2014 Upper 4,233 2,922 3,137 1.9 7.2c‐A7‐H 202/a‐096‐A 094‐G‐01/00 2014 Upper 4,870 4,274 2,738 1.6 6.0c‐7‐H 200/b‐096‐A 094‐G‐01/00 2014 Upper 7,506 4,559 3,171 1.8 6.0b‐17‐H 200/a‐095‐A 094‐G‐01/00 2014 Upper 10,792 6,823 4,441 2.8 10.0
30
Appendix:Egress & Hedging
31
2017 2018 2019Receipt Point Delivery Point Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4
EnbridgeHigh Pine Ft. Nelson T‐North NGTL or Station 2 240 240 240 240 240 240 240 240 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
NGTLTowerbirch Tower Lake or Sunset NGTL 859 859 859 859 859 859 859 859 859 North Montney Aitken Creek NGTL 1,485 1,485 1,485Total NGTL 859 859 859 859 859 859 2,344 2,344 2,344
Cumulative Total 138 138 997 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
32
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
33
Risk Management
Natural GasAECO Swaps AECO Costless Collars Chicago Swaps Stn 2 Diff AECO Puts AECO/Chicago Station 2
Term Volume (GJ/d)
Price(C$/GJ)
Volume (GJ/day)
Put Call Volume (MMBtu/d)
Price (C$/MMBtu)
Volume (GJ/day)
Price (C$/GJ)
Volume (GJ/d)
Put Premium (C$/GJ)
Strike (C$/GJ) % of Corp Forecast
Strike ($/GJ)
Strike ($/GJ)
Q4 2017 64,636 $2.67 10,000 $2.85 $3.21 2,306 $4.17 76,471 ($0.47) 15,337 ($0.190) $2.37 52% 51%Q1 2018 66,810 $2.78 84,500 ($0.46) 20,000 ($0.335) $2.90 43% 55%Q2 2018 35,971 $2.69 62,366 ($0.50) 23% 39%Q3 2018 35,590 $2.69 57,084 ($0.50) 22% 36%Q4 2018 40,260 $2.65 52,471 ($0.49) 25% 33%Q1 2019 27,488 $2.69 49,000 ($0.35) 17% 31%Q2 2019 1,597 $2.86 34,330 ($0.37) 1% 13%Q3 2019 32,674 ($0.38) 13%Q4 2019 20,717 ($0.36) 8%
Annual2017 41,597 $2.77 11,684 $2.83 $3.21 5,540 $4.14 48,708 ($0.50) 3,866 ($0.190) $2.37 54% 45%2018 44,560 $2.70 63,998 ($0.49) 4,932 ($0.335) $2.90 28% 41%2019 7,176 $2.76 34,099 ($0.37) 3% 14%
Condensate & ButaneC$WTI Swaps C$WTI Costless Collars C$WTI Puts
Term Volume (bbl/d)
Price (C$/bbl)
Volume Put CallVolume (bbl/d)
Put Premium (C$/bbl)
Strike (C$/bbl)
% of CorpForecast
Bbl/d Strike (C$/bbl)
Strike (C$/bbl)
Q4 2017 1,233 $65.46 291 $56.77 $68.16 133 ($2.58) $64.40 42%Q1 2018 1,941 $66.88 200 $55.00 $67.25 58%Q2 2018 1,830 $67.13 200 $55.00 $67.25 53%Q3 2018 1,611 $66.89 200 $55.00 $67.25 47%Q4 2018 1,434 $66.64 200 $55.00 $67.25 43%Q1 2019 700 $65.92 200 $55.00 $68.00 23%Q2 2019 677 $65.75 200 $55.00 $68.00 13%Q3 2019 650 $65.54 200 $55.00 $68.00 14%Q4 2019 584 $65.54 200 $55.00 $68.00 12%
Annual2017 951 $64.85 158 $58.96 $72.79 33 ($2.58) $64.40 42%2018 1,702 $66.88 200 $55.00 $67.25 50%2019 652 $65.72 200 $55.00 $68.00 15%
Risk management commodity contracts outstanding (Nov 10, 2017)
34
Appendix:Resources & Reserves
35
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
TcfeAitken 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
36
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
$/bo
e
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 366Total proved 850,804 29,010 170,811 2442 898Proved + 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
37
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
38
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
Jan
Feb
Mar
Apr
May Jun Jul
Aug
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 Oct‐17
Liqu
ids Y
ield (b
bl/M
Mcf)
Black Swan Corporate Liquid Yield
McMahon Black Swan Plant Black Swan Corporate
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
Black Swan’s plant provides superior liquids yield vs. McMahon
North Aitken plant online
Strong gas prices
Liquid RecoveriesAugust 2017 Average 2016
bbl/MMcf CorporateNorth Aitken Corporate
North Aitken
C5+ 25 31 23 29C3/C4 19 22 8 11Total 44 53 31 40
Weak gas prices
39
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 Produ
ction (M
Mcf/d)
Black Swan Wells by Vintage
2017 Completions
2016 Completions
2015 Completions
2014 Completions
2012 & 2013 Completions
Base decline on existing wells: ~35%
40
Appendix:Montney Fairway
41
0
200
400
600
800
1,000
1,200
1,400
1,600
Jan‐14
Apr‐14
Jul‐1
4
Oct‐14
Jan‐15
Apr‐15
Jul‐1
5
Oct‐15
Jan‐16
Apr‐16
Jul‐1
6
Oct‐16
Jan‐17
Apr‐17
Jul‐1
7
Ave Ca
lend
er Day Gas (M
Mcf/d)
Production Month
North Montney Production
ARC
Suncor
Chinook
Polar Star
CNRL
Kelt
Conoco
Todd
Tourmaline
Saguaro
Black Swan
Storm
Canbriam
Painted Pony
Progress
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• Rig activity: 11 rigs operating Oct 2017 vs. one Oct 2016• North Montney production peaked at 1.4 Bcf/d in Jan 2017• Juniors and Intermediates represent ~50% of total North Montney production, up from ~30% three years ago
June 2015 & 2017 volumes impacted by Enbridge McMahon turnarounds
Note: Competitor land positions based on public reports and geoSCOUT
20 km
42
Legend
Black Swan Lands50 m
SiltstoneSiltstone & SandstoneSandstoneMontney 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 M
ontney
200 metres
Lower M
ontney
200 metres
Upp
er M
ontney
65 m
etres
Upp
er M
ontney
65 m
etres
100 km
BCAlbe
rta
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
