liquids rich montney - black swan energy ltd....“black swan has delivered the most consistent well...
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Liquids Rich Montney Value | Scale | Growth
September 2019
2
FT ST JOHN
EDMONTON
MONTNEY
BRITISH COLUMBIA
ALBERTA
10 km
Liquids-Rich Montney 231,000 net acres2
100% working interest
Positioned For Free Cash Flow Generation
1. At $1.60/GJ AECO, US$55/bbl WTI and $1.33 C$/US$2. Land position reflects 360 net sections or 329 net DSUs
Major Milestone Q3 2019Nig Creek Plant & North Montney Mainline On-stream
40,000 – 44,000 Boe/d in 2020
Enhanced Self Funding• EBITDA expanding to ~$130 MM in 20201
• Low maintenance capital of ~$85 MM (18 Hz wells)• Optionality to grow or deliver positive free cash flow
Optimizing Our Infrastructure Advantage• Operated gas plant processing of 210 MMcf/d• Ability to further expand capacity with existing midstream partner• Expanding liquids infrastructure for cost and netback enhancement
Diversifying Revenues with Increased Liquids• Expect to produce 9,000 bbl/d of total liquids• Over 50% of liquids (4,800 bbl/d) is >50◦ API condensate• 1,500 bbl/d of propane to premium FEI overseas markets
Delivering to Multiple Natural Gas Markets• Connected to NGTL, Enbridge and Alliance pipelines• Able to direct 90% of sales gas to AECO in 2020 • Firm capacity to Empress and Dawn starting in 2021
Nig Creek Plant 2
Aitken Creek Plant 1
3
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Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4
2014 2015 2016 2017 2018 2019E
$/b
oe
Opex Transportation G&A Financing
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Q1Q2Q3Q4Q1Q2Q3Q4Q1Q2Q3Q4Q1Q2Q3Q4Q1Q2Q3Q4Q1Q2Q3Q4
2014 2015 2016 2017 2018 2019E
AEC
O (
C$
/GJ)
Cas
h F
low
Cash Flow ($MM) Cash Flow Netback ($/boe) AECO Natural Gas (C$/GJ)
0
100
200
300
400
500
600
2012 2013 2014 2015 2016 2017 2018
Re
serv
es
(MM
bo
e)
PDP PDNP + PUD Probable
Building Momentum Through 2019
Reserve Growth
Lower Montney assigned to Contingent
2019E Controllable
Cash Costs: ~$10/boe
Inception to date 2P FD&A of $5.34/boe
Cash Flow vs. Commodity Prices
Controllable Cash Costs
-
5
10
15
20
25
30
35
40
45
Q1
Q2
Q3
Q4
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Q4
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Q4
2013 2014 2015 2016 2017 2018 2019E
Avg
. Dai
ly P
rod
uct
ion
(m
bo
e/d
)
Production Growth
Delineation Development
Running less than one rig annually delivered:
>50% CAGR Q4/14 – Q4/18
Increasing Q4 cash flow
4
7.2
8.2
12.2
9.3 8.7 8.5
10.1
11.3
10.2 10.3
9.4
0.0
2.0
4.0
6.0
8.0
10.0
12.0
14.0
7-H 54-D 22-C 92-C 19-E 42-D 2-C 72-C 32-C 44-C 52-C
2014 2015 2016 2017 2018
Avg
EU
R (
Bcf
/wel
l)
Upper Montney Hz - Avg EUR by Pad
EUR (on-stream) Average EUR
Established Track Record
Predictable Well Results• Average EUR: 9.4 Bcf since 2012 (69 wells)1
• Average EUR: 10 Bcf (last 50 wells)
• Initial yield 40-70 bbl/MMcf (50-60% C5+)
• Type curve IP30: 1,100 boe/d (25% liquids)
Multi-Well Pad Development• 11 multi-well pads on production
• 300m inter-well spacing
• Type curve developed based on pad wells
• Entire Aitken core area delineated
1. Not normalized for completions. 12 additional Hz have been completed with minimal production history
“Black Swan has delivered the most consistent well results among any Montney producer in our universe while driving down both
capital and operating costs over time” - Cormark, May 2018
10 km
Aitken Core Area
42-D
Upper Montney Pad Wells
Lower Montney + Pilot Wells
19-E7-H
54-D
2-C22-C
32-C
52-C
72-C
92-C
44-C
5
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$500
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$3.0
$3.5
$4.0
$4.5
1 10 20 30 40 50 60 70 80
2013-2014
2015 2016 2017 2018 2019
Co
st p
er
late
ral m
Dri
llin
g C
ost
(M
M)
Montney Hz Drilled
Black Swan Drilling Cost
Cost per Well
Cost per m
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$1,000
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$7.0
1 10 20 30 40 50 60 70 79
2013-2014
2015 2016 2017 2018 2019
Co
st p
er
Ton
ne
Co
mp
leti
on
Co
st (
$M
M)
Montney Hz Completed
Black Swan Completion Cost
Cost per Well
Cost per Tonne
Optimizing Cost Structure & Wellbore Design
$1,000 per lateral metre
$1,000 per tonne
Continuous Optimization• Base design is 1800 m and 1.0 T/m
• Tested wells up to 2700m length and 1.3 T/m
• Plan to continue testing longer wells & higher intensity in 2020
Base Design For Development Plan$4 MM D&C and 9 Bcf per well
$1,200 per tonne
1. Wells averaged 2010m length & 2010T proppant
Established Cost Structure• From Q3 2015 up to Q4 2018: consistent
normalized D&C costs ($4.0 MM for base design well)
• Over last 23 wells1: normalized completion cost has decreased• 10% below base design, normalized for
length
6
25%
50%
81%
10%
25%
43%
0%
10%
20%
30%
40%
50%
60%
70%
80%
90%
100%
$1.20/GJ AECO$50/bbl WTI
$1.60/GJ AECO$55/bbl WTI
$2.00/GJ AECO$60/bbl WTI
IRR
9.0 Bcf Type Curve Economics
Half Cycle
Full Cycle
0
50
100
150
200
250
0
1,000
2,000
3,000
4,000
5,000
6,000
7,000
0 60 120 180 240 300 360 420 480
C5
+ (b
bl/
d)
Gas
Rat
e (
Mcf
/d)
Normalized Days
Black Swan Upper Montney Performance vs Type Curve1
Average Gas
9.0 Bcf Type Curve
Average C5+
180 mbbl C5+ Type Curve
Compelling Economics: Low Cost, Liquids Rich, Hot Gas
Liquids Contribution• Total 360 mbbl per 9 Bcf well:
• 180 mbbl condensate (C5+); half recovered in first 5 years
• 180 mbbl LPG (50% propane & 50% butane)
1. C5+ includes lease & plant recoveries; C3/C4 yield from the plant is additional and not shown2. $1.60/GJ AECO & $55/bbl WTI
Aitken Montney Economics2
Half Cycle Full Cycle
Gas EUR Bcf 9.0 9.0
Liquids EUR mbbl 360 360
DCET $MM 4.5 4.5
Infrastructure $MM 0 1.3
Netback (Year 1) $/boe 11.93 11.16
IRR % 50% 25%
NPV10 $MM 4.5 2.5
Payout Years 1.7 3.1
F&D $/boe 2.61 3.36
Recycle Ratio 3.46 2.68
Break-Even @ $55/bbl $/GJ 0.60 1.05
Material Upside • Corporate planning based on 9.0 Bcf & $4MM D&C
• Recent results indicate 10.0 Bcf & $3.8MM D&C
• Upside of $1.1MM NPV per well
7
Infrastructure: Key Component of Integrated Growth Plan
North Aitken Plant 1
Sales gas connected to Enbridge T-North, NGTL
North Montney & Alliance
50 MMcf/d compression & dehy, volumes
flow to McMahon for processing
10 km
Note: Black Swan qualified for $37MM of BC infrastructure credits with $10 MM received to date
Core Infrastructure In PlaceNorth Aitken (Plant 1): 110 MMcf/d (current capacity)• Liquids recoveries capable of ~40 bbl/MMcf (>50% C5+)
Nig Creek (Plant 2): 100 MMcf/d (initial capacity)• Phase A: On-stream Sept 2, 20191
Positioned for Low Cost Growth•Nig Creek Phase B: Deep cut 80 MMcf/d (on-stream TBD)•North Aitken Phase B: Deep cut 70 MMcf/d (on-stream TBD)• >370 MMcf/d sales gas capacity to TC Energy, Enbridge & Alliance• >55 km of raw gas gathering in place including trunk lines to serve
future pads• Fresh water license & storage to support >100 Hz wells/year
Strategic Liquids Handling• LPG pipeline under construction to AltaGas fractionation facility at
North Pine• Expected on-stream in Q4 2019• Removes trucking costs for all NGL volumes• Propane access to RIPET for premium FEI pricing• Sized to accommodate Nig Creek Phase B volumes
• 14 km of condensate pipeline constructed to provide optionality for future tie-ins to regional condensate infrastructure
Nig Creek Plant 2
1. Nig Creek flowing at reduced capacity initially, will ramp to capacity once the TC Energy North Montney Mainline is on-stream
8
$0.00
$2.00
$4.00
$6.00
$8.00
$10.00
Pee
r 1
Pee
r 2
BSE
Pla
nt
Pee
r 3
Pee
r 4
BSE
Pee
r 5
Pee
r 6
Pee
r 7
Pee
r 8
Pee
r 9
Pee
r 1
0
Pee
r 1
1
$/b
oe
Owned & Operated Infrastructure: Lower Costs & Higher Netbacks
Plant at capacity of 110 MMcf/d
Stable Liquids: ~45 bbl/MMcf
Top Tier 2019E Operating Costs
Source: National Bank Financial and Black Swan
Plant operating at >98% run time
Plant Capacity
0
20
40
60
80
100
120
Gas
Pro
du
ctio
n (
MM
cf/d
)
Inlet Gas (MMcf/d) Inlet Capacity (MMcf/d)
0.0
10.0
20.0
30.0
40.0
50.0
60.0
Liq
uid
s Y
ield
(b
bl/
MM
cf R
aw)
Condensate Butane & Propane
Future Processing Outlook
• Processing capacity will be through Black Swan facilities
• Installation of deep cut will capture additional liquids
• Operating costs will decrease as capacity grows
• Future expansions are backstopped by long term egress commitments for both gas and liquids
9
Nig Creek Gas Plant: Major Milestone Achieved
Execution – On Budget, On Schedule
•Commissioned and on-stream Sept 2, 2019
•Three pads (22 wells) required to fill Nig Creek (2A)• >100 MMcf/d currently behind pipe• Approved well licenses for 2 yrs drilling (2020+)
•Capital pre-spent to facilitate expansion with deep cut to 180 MMcf/d
Emissions Reduction Initiatives
•Utilizing the most current technology to reduce carbon footprint
•Solar power at well pads
•Waste heat recovery at plant to reduce greenhouse gas emissions by 10,000 tonnes annually
•Upside with future access to hydro electric power
“Off the grid” - Solar panels provide power at well pad sites
Minimizing disturbance – multiple pipelines installed concurrently
10
0.0x
0.5x
1.0x
1.5x
2.0x
2.5x
Pee
r 1
Pee
r 2
Pee
r 3
Pee
r 4
Pee
r 5
Pee
r 6
Pee
r 7
BSE
Pee
r 8
Pee
r 9
Pee
r 1
0
BSE
20
21
E
Pee
r 1
1
20
20
E EB
ITD
A/S
ust
ain
ing
Cap
ex
Scalable Growth With Low Sustaining Capital
0
10,000
20,000
30,000
40,000
50,000
60,000
70,000
2019E 2020E 2021E 2022E 2023E
Pro
du
ctio
n (
bo
e/d
)
Expansion OptionalityOption for
continued growth
Low Sustaining Capex vs. EBITDA
1. Assumes production is held flat post Nig Creek 2A commissioning2. LPG realizations as % of C$WTI: Butane 28%, Propane 14%
•Well performance and cost structure provide for low sustaining capex requirements
•At 43,000 boe/d1 ($1.60/GJ AECO & US$55/bbl WTI):• Cash flow: $120 MM2
• Maintenance capital: $85 MM • Free cash flow: $35 MM
•Planned Nig Creek expansion (2B) enhances EBITDA in 2021, driving top tier ranking
Building Capacity in Stages
Nig Creek (2A) Sept 19: 43,000 boe/d
Nig Creek (2B) TBD: 62,000 boe/d
•Execution strategy offers optionality at each stage for:
• Future growth
• Free cash flow generation with flat production
•Growth is underpinned by firm capacity for gas and liquids; can adjust pace to commodity prices
•Expansions funded by cash flow and debt; leverage peaks ahead of commissioning but declines quickly
Performance Driven
Source: National Bank Financial and Black Swan Energy. Peers include: AAV, ARX, BIR, CR, NVA, PEY, PONY, POU, SRX, TOU, VII
11
0
50
100
150
200
250
300
350
400
Sep Dec Mar Jun Sep Dec Mar Jun Sep Dec Mar Jun Sep Dec
2019 2020 2021 2022
Sale
s G
as (
MM
cf/d
)
Processing Capacity vs Egress Commitments
Nig Creek (2A)
Aitken Creek
Nig Creek (2B)
Aitken Creek (Expansion)
McMahon
Connection to NGTL through NMML: a step toward diversification
1. NGTL is part of the TC Energy pipeline system2. Renewable
Note: Unutilized tolls: $1.1 MM/month post Plant 2A; $0.5MM/month post Plant 2B
Egress Via Three Major Gas Pipelines
Alliance Capacity2
Enbridge Capacity
NGTL1 ExpansionEnbridge Expansion
Spruce Ridge ProjectBlack Swan:60 MMcf/dEst. Q4/21
North Montney MainlineBlack Swan:229 MMcf/dEst. Q3/19
Existing Pipelines
• Egress on all three Canadian gas transmission systems enables netback optimization
• Egress grows to >390 MMcf/d• Option to flow up to 90% on NGTL by late 2019
• 50 MMcf/d service to Empress starting Q2/21 and 20 MMcf/d service to Dawn Q4/21 provides additional market diversification
British Columbia
Vancouver
Kitimat
Fort St. John
Alliance
EnbridgeNGTL
Existing Pipelines
North Montney Mainline
Existing ProcessingPlanned Processing
12
NGTL
ENBRIDGE
ALLIANCE
NORTHERNBORDER
TC ENERGY MAINLINE
GREAT LAKESIROQUOIS
VIKING
ROVER
NEXUS
FOOTHILLS
GTN
VECTOR
CHICAGO
DAWN
AECO
SKAB
BC
MB ON
QC
STN 2
ROCKIES EXPRESSRUBY
14%
57%
14%
14%
2019 Gas Diversification
ATP Stn 2 AECO AECO or Stn 2
Delivering Liquids & Natural Gas to Diverse Markets
EMPRESS
ATPRIPET to FEI
10%
44%25%
21%
2021 Gas Diversification
Stn 2 AECO AECO or Stn 2 Empress
9%
12%
60%
19%
2020 Gas Diversification
ATP Stn 2 AECO AECO or Stn 2
Diversifying Black Swan’s Marketing Portfolio• NMML will provide access to AECO and other potential TC
Energy markets in eastern Canada and the U.S.• RIPET deliveries to FEI propane markets commenced May 2019
13
Risk Management: Financial Hedging & Physical Diversification
Natural Gas• Actively working to achieve downside coverage
and diversification for natural gas1
• Hedged prices shown reflect the combination of swaps, collars and puts
• Production beyond volumes shown will be directed to the highest netback market
Condensate• Condensate hedging is accomplished with C$WTI
contracts
Propane• Propane hedges are in place for a portion of
delivered volumes• Majority of unhedged propane sold to offshore
FEI markets
Note: Average hedge price based on Aug 14 strip
Currently hedge up to three years for all products
1. Floating NYMEX achieved through financial hedges which lock in a fixed Basis to AECO
$0.00
$0.50
$1.00
$1.50
$2.00
$2.50
0
50,000
100,000
150,000
200,000
250,000
Q419 Q120 Q220 Q320 Q420 Q121 Q221 Q321 Q421 Q122 Q222
Natural Gas Hedging
Total Hedged Gas Floating NYMEX Floating EmpressFloating Dawn Floating Chicago Averaged Hedged Price
GJ/d $/GJ
$0
$20
$40
$60
$80
$100
0
1,000
2,000
3,000
4,000
Q419 Q120 Q220 Q320 Q420 Q121 Q221 Q321 Q421 Q122
Condensate Hedging
Swaps Collars Puts Swap Price
Collar Floor Collar Cap Put Strike
bbl/d $/bbl
$0
$10
$20
$30
$40
$50
$60
0
200
400
600
800
1,000
1,200
Q419 Q120 Q220 Q320 Q420
Propane Hedging
Conway Swaps FEI Swaps Conway Swap Price FEI Swap Price
$/bblbbl/d
14
2019 Guidance: Production Targets Unchanged with Lower Capital
• Drilling capital budget (includes maintenance to stay flat):
• Wells: $93MM (23 Hz drills, 20 completions, 20 tied-in)
• Infrastructure capital budget (Plant 2 activity):
• Plant 2 construction: $53MM
• Pipelines: $14MM
• Gathering lines, roads, other: $21MM
• Growth capital (Plant 2 expansion):
• Plant 2B: $5MM
1. Based on annual pricing of $1.50/GJ AECO, -$0.32/GJ Station 2 to AECO differential, US$52/bbl WTI and $1.31C$/US$, Edm C5+ 83% of WTI, C4 55% WTI2. Based on annual pricing of $1.65/GJ AECO, -$0.55/GJ Station 2 to AECO differential, US$56/bbl WTI and $1.33C$/US$, Edm C5+ 92% of WTI, C4 10% WTI3. Bank facility excludes $25 MM accordion for additional syndicate participation; $31 MM allocated to LCs; term notes have 9% coupon and mature Jan 2024
2019 Guidance
Dec 20181 Sept 20192
Production (boe/d)
Average 27,000 – 29,000 27,000 – 29,000
Exit 40,000 – 42,000 40,000 – 42,000
Capital ($MM) $200 $185 - $190
Cash flow ($MM) $65 - $75 $55 - $65
Exit Net Debt ($MM) $270 - $280 $270 - $280
2019 Capital Program
Balance sheet strength retained3:$140MM capacity on $275MM bank facility exiting 2019 US$100MM of 7 year term notes
D&C costs ~8% below budget YTD
$3.6MM of infrastructure royalty credits received
Long lead spending maintains on-stream flexibility10 km
15
Water pump station
Balanced Execution - Environment, Health & Safety, Community
• Ranked No. 1 for LMR1 among all BC oil and gas producers
• Re-used 100% of our produced water since June 2014
• Water license supports 100+ Hz wells per year2
• >2.2 MMbbl of fresh water storage capacity constructed
• Continuous innovation to reduce GHG emissions
Health & SafetyEnvironment
• Health, Safety & Environment Policy reviewed and signed off annually
• Integrated Safety Management System
• Low annual TRIF3
• Certificate of Recognition audit completed in 20184 with score of 98%
Community Involvement• Coordinated First Nations Training
Initiative
• Leading participant in annual Movember fundraising since 2014
• Active corporate giving
• Raised over $385k for charitable causes since inception
1. LMR (Liability Management Rating)2. Through Dec 31, 2021, with renewal provisions3. TRIF (Total Recordable Incident Frequency) as measured by incident per 200,000 man hours4. From the Alberta Association For Safety Partnerships
0.55 0.59
0.96
0.83
0.00
0.35
0.61
2012 2013 2014 2015 2016 2017 2018
Total Recordable Incident Frequency
Graduation ceremony of the First Nations Training Initiative
16
Aitken Area: Depth of Inventory Underpins Long Term Planning
Core Area: 400 Hz Locations Remaining •Upper Montney Hz inventory delineated in the Aitken
core development area
•10-20 years of locations remain based on a production plateau of 60,000 to 100,000 boe/d
Dominant North Montney Position • Entire acreage delineated by offset competitor activity
•>2,600 Hz locations provides long term visibility
•Offset Upper Montney completions by Storm & CNRL at Nig indicate EURs > 15 Bcf
• Increased liquids exposure in the Lower Montney•Remaining acreage & landing zones provide potential to:
•Backstop long term free cash flow generation, or• Increase peak production
Aitken Core Development Area
Laprise
Jedney
Nig
Birch
Gundy
17
$0
$2
$4
$6
$8
$10
0%
20%
40%
60%
80%
100%
Strength Across Multiple Factors Drives Long Term Profits
1. Internal estimates, Montney gas & liquids rich wells 2. BSE operating costs include 27 MMcf/d processed through McMahon and AltaGas 50% ownership in the North Aitken plant3. Revenue, Royalty, Opex, G&A, Interest based on 5 year plan at current strip pricing4. Infrastructure costs averaged across drilling for a 10 year production plateau
$4.52
80%
Source: Internal estimates, National Bank Financial & company reports; peer group includes: AAV, ARX, BIR, Canbriam, CR, KEL, NVA, PONY, Saguaro, SRX, TOU, VII
Infrastructure Advantage
2019E Operating Costs ($/boe)2
Liquids Contribution
Gas Weighting (%) 2019E
BSE
BSE$0.0
$2.0
$4.0
$6.0
$8.0
$10.0
$12.0
0.0
2.0
4.0
6.0
8.0
10.0
12.0
Well Performance
9.1
$4.0
Average EUR Bcf (Wells Drilled Last 36 Mos.)1
2019E Drilling & Completions Cost ($MM)
Competitive Capital Costs
BSE
BSE
$6.05/boeProfit:
2.8XRecycle Ratio
Forward Economics3
Full Cycle ($/boe)
Revenue $18.65
Royalty 1.05
Opex + transport 6.50
G&A + interest 1.65
Cash Netback $9.45
Half cycle F&D $2.60
Infrastructure4 $0.80
Full cycle F&D $3.40
18
Appendix
Liquids Rich Montney
Value | Scale | Growth
19
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 Energy. 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 Energy. 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 Energy. 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. Christine currently serves on the Board of the Petroleum Acquisition and Divestiture Association.
20
Black Swan Energy Board of Directors
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.
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.
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.
Evan Hazell, P. Eng. MBA Evan has been involved in the global oil and gas industry for over 30 years, both as a petroleum engineer and as an investment banker. At present, he serves as a Director of non-profit and community organizations Opera America, Calgary Municipal Land Corporation and Calgary YMCA. From 1998 to 2011, Mr. Hazell acted as a managing director at several financial institutions including HSBC Global Investment Bank and RBC Capital Markets. Mr. Hazell holds a Bachelor of Applied Science degree from Queen's University, a Master of Engineering degree from the University of Calgary, and an MBA degree from the University of Michigan.
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.
David B. Krieger, MBA 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 Wharton, an M.S. with high honors from the Georgia Institute of Technology and an MBA with distinction from Harvard Business School.
Roy Ben-Dor, MBARoy 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.
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.
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.
21
2019 2018 2018 2017 2017
Q2 (3) Q1 Full Year Q4 Q3 Q2 Q1 Full Year Q4 Q3 Q2 Q1
Production
Gas (mcf/d) 114,449 120,169 121,614 120,960 125,401 121,914 118,105 88,559 116,138 85,769 66,194 85,832
NGL (bbl/d) 4,439 5,180 5,176 5,085 5,249 5,449 4,917 3,166 4,838 3,501 1,868 2,427
Total (boe/d) 23,514 25,208 25,445 25,245 26,149 25,768 24,601 17,926 24,194 17,796 12,900 16,732
Financial ($ 000)
Net Operating Income1 7,019 22,936 109,356 15,799 31,949 29,172 32,445 74,435 23,425 14,130 14,241 22,639
EBITDA2 7,617 23,885 98,666 19,152 24,452 24,024 31,038 84,282 30,855 19,631 13,074 20,722
Funds from operations 3,947 20,616 82,786 15,754 19,916 19,994 27,122 71,025 27,132 16,347 9,705 17,841
Capex (incl. A&D) 50,350 57,237 132,956 (76,480) 29,678 22,071 44,774 180,623 25,735 50,972 54,539 49,377
Capital Structure ($ 000)
Working Capital Deficit (Surplus) 7,227 36,146 7,945 7,945 8,659 (758) 11,144 4,688 4,688 23,176 23,916 (8,140)
Bank Debt 82,808 7,494 - - 91,707 91,420 77,541 66,147 66,147 48,759 13,091 -
Term Notes 132,439 133,902 133,826 133,826 133,517 133,466 133,829 132,275 132,275 128,513 129,513 129,590
Total Net Debt 222,474 177,542 141,771 141,771 233,883 224,128 222,514 203,110 203,110 200,448 166,520 121,450
Total Credit Facility 300,000 275,000 275,000 275,000 300,000 300,000 270,000 270,000 270,000 250,000 200,000 200,000
Netback Summary ($/boe)
Net Revenue 12.19 18.18 18.92 14.72 19.40 18.65 23.12 18.99 17.13 15.49 22.13 23.07
Hedging Gain (Loss) 1.16 1.10 (0.03) 3.33 (2.12) (1.32) 0.08 2.79 5.20 4.06 0.27 (0.20)
Royalties (0.71) (0.87) (0.95) (0.78) (0.98) (1.02) (1.04) (0.89) (0.72) (0.65) (1.02) (1.26)
Opex (5.11) (4.16) (3.28) (4.14) (2.87) (3.02) (3.10) (3.73) (2.56) (3.25) (5.74) (4.39)
Transportation (3.10) (3.04) (2.92) (3.00) (2.27) (2.17) (4.32) (3.00) (3.32) (2.96) (3.23) (2.34)
Operating Netback 4.43 11.21 11.74 10.13 11.16 11.12 14.74 14.16 15.73 12.69 12.40 14.83
General & Administrative (0.92) (0.72) (1.18) (1.92) (0.94) (1.00) (0.86) (1.44) (2.00) (0.83) (1.44) (1.27)
Processing Income 0.04 0.04 0.06 0.04 (0.06) 0.12 0.14 0.16 0.13 0.14 0.19 0.20
Interest/Other Expense (1.71) (1.46) (1.70) (1.46) (1.89) (1.71) (1.77) (2.02) (1.67) (2.02) (2.85) (1.91)
Cash Flow From Operations 1.84 9.07 8.92 6.79 8.28 8.53 12.25 10.86 12.19 9.98 8.28 11.85
Historical Financial Summary
1. NOI excludes realized hedging gains/losses2. EBITDA excludes unrealized hedging gains/losses3. Preliminary values, subject to Audit Committee approval
22
Type Curve Assumptions
1. AECO Delivery: Economics assume volumes flow through new Black Swan owned infrastructure (reflects full cycle) with tolls to AECO on the NGTL system and gas realizations priced equal to AECO
2. FX rate of C$1.33/US$ applied to US$WTI prices
3. Economics include equip & tie-in costs of $0.5 MM/well for total well costs of $4.5 MM
4. Black Swan pays BC Crown royalties calculated on a sliding scale for gas based on price and production rate & fixed percentage of revenue for liquids
5. Pricing relative to C$WTI: C5+: 87%, C4: 28%, C3: 14% at US$55/bbl oil (realizations include price offsets for transportation & terminal fees; trucking of $4.00/bbl included in opex & transportation)
6. Opex & transportation represent the average cost during the first 12-months
Assumptions
AECO Delivery
D&C Cost ($MM, excl. $0.5 MM tie-in) $4.0
EUR (Bcf) 9.0
IP30 - Total (boe/d) 1,160
Heat Content (MMBtu/mcf) 1,150
Liquids Yield (bbl/MMcf) 40
Price Differential to AECO ($/GJ) -
Royalty Drilling Credit ($ MM) $1.05
Opex & Transportation – 1st Year ($/boe) $5.80
Opex & Transportation – Full life ($/boe) $7.00
Full Cycle – Infrastructure ($/boe) $0.75
Full Cycle – G&A ($/boe) $0.90
23
4,600
5,100
5,600
6,100
6,600
7,100
7,600
2014 2015 2016 2017 2018 2019
1400
1600
1800
2000
2200
2400
Fee
t
Me
tre
s
Completed Well Length
Completions: Optimization of Design
2019 Completion Design
Open hole ball drop• 1,800 to 2,400m lateral length varied to optimized land usage (2000m avg)• 60 m port spacing• Proppant: 60 tonne/stage, 1.0 tonne/m loading, 1,800-2,400T/well• ~10,000 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• 2018/2019 – Continue with short stage design, relaxing parameters on well
length and sand loading to support low cost, best economic design• Continue to evolve forward looking design metrics with additional well/pad
performance analysis
Completion Design Evolution
Optimizing Recovery Per DSU• Tighter stage spacing (60m vs 90m)• Tested sand intensity with wider inter-well spacing• Fluid additive technology, diversion techniques continue to evolve• Evaluate higher stage count systems for future tests• Increased focus on optimized land utilization & surface facilities
0
50
100
150
200
250
300
350
2014 2015 2016 2017 2018 2019
0
20
40
60
80
100
Feet
Me
tre
s
Stage Spacing
330
430
530
630
730
830
930
2014 2015 2016 2017 2018 2019
0.5
0.7
0.9
1.1
1.3
1.5
lbs/
ft
ton
ne
/m
Proppant Concentration
24
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
• Details collapsed for pads where all wells have >365 days of production history, averages represent the average of all Upper Montney wells on the pad
Note: Gas rates shown are raw
Internal UWI Completion Montney IP30 / well IP90 / well IP365 / wellCum to Jun/19 EUR
Reference (Year) Target (mcf/d) (mcf/d) (mcf/d) (Bcf) (Bcf)
9 Bcf Type Curve (restricted) 5,900 5,300 3,900 9.0
44-C Well Pad (4 wells) 2018 10.3
d-44-C 200/a-066-C 094-H-04/00 2018 Upper 5,879 NA NA 0.2 9.5
d-A44-C 200/d-066-C 094-H-04/00 2018 Upper 6,285 NA NA 0.4 10.5
d-B44-C 200/c-065-C 094-H-04/00 2018 Upper NA NA NA 0.1 NA
d-C44-C 200/b-075-C 094-H-04/00 2018 Upper 7,247 NA NA 0.2 11.0
32-C Well Pad (6 wells) 2018 4,901 4,908 NA 8.5 10.2
a-32-C 200/a-020-B 094-H-04/00 2018 Upper 4,583 NA NA 0.8 9.0
a-A32-C 200/d-020-B 094-H-04/00 2018 Upper 4,168 4,233 4,255 1.8 11.0
a-B32-C 200/a-030-B 094-H-04/00 2018 Upper 5,597 5,437 4,610 1.8 11.0
a-C32-C 200/b-053-C 094-H-04/00 2018 Upper 5,150 5,133 4,469 1.6 11.0
a-D32-C 200/a-054-C 094-H-04/00 2018 Upper 5,347 5,234 4,326 1.7 10.0
a-E32-C 200/d-044-C 094-H-04/00 2018 Upper 4,563 4,504 NA 0.8 9.0
72-C Well Pad (6 wells) 2017 6,438 5,717 4,713 11.9 11.3
a-72-C 200/b-059-B 094-H-04/00 2017 Upper 6,545 5,967 4,931 2.4 12.5
a-A72-C 200/a-060-B 094-H-04/00 2017 Upper 6,744 6,295 5,218 2.5 13.0
a-B72-C 200/d-050-B 094-H-04/00 2017 Upper 6,696 5,907 4,888 2.2 12.0
a-C72-C 200/c-093-C 094-H-04/00 2017 Upper 5,321 4,749 3,805 1.8 9.0
a-D72-C 200/a-094-C 094-H-04/00 2017 Upper 5,827 4,949 NA 1.3 10.0
a-E72-C 200/c-084-C 094-H-04/00 2017 Upper 7,494 6,437 4,725 1.7 11.0
42-D Well Pad (8 wells) 2017 5,373 4,752 3,711 11.4 8.5
d-42-D 200/a-073-D 094-H-04/00 2017 Upper 5,400 5,018 3,813 1.7 9.0
d-A42-D 200/b-073-D 094-H-04/00 2017 Upper 5,710 4,982 4,089 1.6 9.0
d-B42-D 200/c-063-D 094-H-04/00 2017 Upper 5,480 4,713 3,571 1.5 8.0
d-C42-D 200/d-064-D 094-H-04/00 2017 Upper 4,904 4,297 3,370 1.3 7.5
d-D42-D 200/d-040-C 094-H-04/02 2018 Upper 6,119 5,747 4,261 1.4 9.5
d-E42-D 200/a-040-C 094-H-04/02 2018 Upper 5,875 5,192 NA 1.1 9.0
d-F42-D 200/b-040-C 094-H-04/02 2018 Upper 6,099 5,968 4,245 1.5 9.0
d-G42-D 200/d-064-D 094-H-04/00 2018 Upper 4,782 4,007 NA 1.3 7.0
2-C Well Pad (6 wells) 2017 Upper 5,997 5,231 4,032 13.8 10.1
19-E Well Pad (3 wells) 2016 Upper 4,647 4,674 3,914 7.9 8.7
92-C Well Pad (6 wells) 2016 Upper 5,231 4,881 3,876 13.8 9.3
22-C Well Pad (6 wells) 2015 Upper 6,786 6,327 4,857 20.3 12.2
54-D Well Pad (8 wells) 2015 Upper 5,016 4,770 3,766 21.5 8.2
7-H Well Pad (5 wells) 2014 Upper 6,850 4,645 3,372 11.3 7.2
25
0
1,000
2,000
3,000
4,000
5,000
6,000
7,000
8,000
9,000
0 60 120 180 240 300 360 420 480 540 600
Mcf
/d
Pad Operations: Core Area Delineated with High Rate Pads
Upper Montney Pad Performance Tracking Type Curves
2-C
92-C
7-H
19-E
22-C54-D
10 km
Upper Montney Pad Wells
Aitken Core AreaPlot
Legend PadYear
CompletedWells/
Pad
AvgD&C
($MM)Avg EUR
(Bcf)
32-C 2018 6 4.5 10.2
72-C 2017 6 4.7 11.3
42-D 2017/2018 8 3.9 8.5
2-C 2017 6 4.9 10.1
19-E 2015/16 3 3.72 8.7
92-C 2016 6 3.9 9.3
22-C 2015 7 4.1 12.21
54-D 2015 8 4.6 8.2
7-H 2014 5 6.4 7.21
10.5 Bcf9.0 Bcf7.5 Bcf
Type Curves
Black Swan’s type curves reflect a restricted draw down
42-D
72-C
Normalized Days
Mcf/d
1. Pads include one Lower Montney pilot well not included in the average EUR
2. Avg cost for two 2016 wells, 2015 well cost $9 MM D&C
32-C
Lower Montney + Pilot Wells
26
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 Jan/18 Apr/18 Jul/18 Oct/18 Jan/19 Apr/19 Jul/19
Liq
uid
s Y
ield
(b
bl/
MM
cf)
Black Swan Corporate Liquid Yield
Black Swan Plant McMahon Black Swan Corporate
Aitken Creek: Superior Recoveries• 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 at Aitken Creek North Gas Plant
Black Swan’s plant provides superior liquids yield vs. McMahon
Initial Lease Condensate (bbl/MMcf)
Aitken Creek North Plant
27
-5%
0%
5%
10%
15%
20%
25%
30%
35%
-$5.00
$0.00
$5.00
$10.00
$15.00
$20.00
$25.00
SRX BSE PONY PEY ARX AAV TOU BIR CR NVA KEL
20
18
PD
P R
ese
rve
s G
row
th
PD
P F
D&
A (
$/b
oe
)
2018 Year-end PDP FD&A & Reserves Growth vs. Montney Peers
PDP FD&A 2018 PDP Reserves/Share Growth
-$4.00
-$2.00
$0.00
$2.00
$4.00
$6.00
$8.00
$10.00
BSE PONY AAV SRX TOU BIR CR PEY KEL ARX NVA
2P
FD
&A
($
/bo
e)
3 Year 2P FD&A (including FDC) vs. Montney Peers
Growing PDP and Proved Reserves for Less
1. Source: Company reports (peers incl.: AAV, ARX, BIR, CR, KEL, NVA, PEY, PONY, SRX and TOU)2. Capital include the cost of the Carmel Bay acquisition, North Aitken Creek Gas Plant, land &
changes in Future Development Capital (FDC)
Leading Y/Y PDP Growth • Delivered PDP FD&A of $0.84/boe
• Significant investment in owned infrastructure • Excluding AltaGas proceeds 2018 PDP FD&A:
• $5.53/boe
Proven Cost Competitiveness• 3-Year rolling FD&A $/boe (incl. FDC)2:
• PDP $4.57 | 1P $2.94 | 2P -$3.27
BSE
BSE
BSE PDP FD&A BSE AltaGas Proceeds
28
Growth Plan Supported by Low Cost Reserves
1. GLJ January 1, 2019 price forecast, includes 1P FDC $0.5 B and 2P FDC $1.3 B2. Natural gas volumes converted to barrels of oil equivalent at 6,000 cubic feet per barrel (6 mcf = 1 boe)
2018 PDP adds replaced 162% of annual production2018 Company Interest Reserves
Net Present Value1 Before Tax
($MM)
Gas (MMcf)
NGLs (mbbl)
Total (mboe)2 0% 10%
PDP 336,711 14,011 70,129 1,027 542
Total proved 880,243 38,205 184,912 2,492 1,060
Proved + probable 2,104,407 92,469 443,203 7,072 2,137
62
92
127
12 11
2018 Booked Locations
16%
26%58%
2018 Total Reserve Volume
PDP
Proved Non-Producing
Probable
Locations booked continue to focus on near term Upper Montney targets, leaving upside to unbooked zones
9.5410.28 9.96
7.14 6.866.08
5.34
0.00
2.00
4.00
6.00
8.00
10.00
12.00
2012 2013 2014 2015 2016 2017 2018
F&D
($
/bo
e)
Inception to Date 2P F&D (including FDC)
Other Land Infr. D&C
29
North Montney Mainline Construction Underway
• NMML construction commenced Aug 2018• Expected fall 2019 on-stream• Production to flow onto the NGTL system• Part of multi billion dollar expansion by TCPL to improve
system access to export markets• Provides Black with with potential LNG optionality
• LNG Canada’s1 Coastal Gas Link project
Eastern and Western Market Potential
Source: NEB
-
200
400
600
800
1,000
1,200
1,400
1,600
2019 2020 2021
MM
cf/d
North Montney Producer Ramp Up
Shipper J
Shipper K
Shipper A
Shipper C
Shipper F
Shipper E
Shipper D
Shipper B
BSE
Progress
NGTL
British Columbia
Vancouver
Kitimat
Fort St. John
1. LNG Canada announced positive FID Oct 2, 2018
North Montney Mainline
30
Black Swan & AltaGas Strategic Infrastructure Co-ownership
110 MMcf/d North Aitken (Plant 1)
180 - 198 MMcf/d Nig Creek Site (Plant 2)
1. Includes existing 110 MMcf/d North Aitken Gas Plant (Plant 1), the 100 MMcf/d initial phase of the Nig Creek Gas Plant (Plant 2) under construction and planned expansions of both facilities
• Investment by AltaGas for 50% WI in certain existing and future natural gas processing plants of Black Swan:• $136MM in 2018 • ~$50MM in Q4/19
•The Aitken Creek Processing Facilities1 will have ~210 MMcf/d of processing capacity• Potential to increase up to 360 MMcf/d with future
expansions• No take or pay
•Black Swan to remain operator of the gas processing facilities•Strategic liquids handling
• 56 km of new LPG pipeline to bring Black Swan C3/C4 to the AltaGas North Pine Fractionation Facility
• Propane exports to FEI markets via the AltaGas Ridley Island Export Terminal (RIPET)
56km of new LPG pipeline
AltaGas TownsendGas Plant
AltaGas North Pine Fractionation
Facility
Aitken Creek Processing Facilities1
Expandable to 360 MMcf/d
10 km
31
Hedge Position & Pricing Summary
Dated: Aug 15, 2019
Condensate & ButaneC$WTI Swaps
(C$/bbl) C$WTI Costless Collars (C$/bbl) C$WTI Long Puts (C$/bbl) C$WTI Long Calls (C$/bbl)
TermVolume (bbl/d)
PriceVolume (bbl/d)
Volume (bbl/d)
Put Premium
StrikeVolume (bbl/d)
Call Premium
StrikeFloor Cap
Q3 2019 1,963 $70.73 200 $55.00 $68.00 600 ($5.36) $73.81 550 ($5.97) $76.46 Q4 2019 2,477 $71.55 400 $65.00 $82.56 700 ($5.07) $66.48 Q1 2020 2,332 $68.41 1,100 $68.64 $83.46 100 ($5.96) $77.00 Q2 2020 2,440 $68.62 1,100 $68.64 $83.46Q3 2020 2,340 $68.08 800 $69.38 $84.98Q4 2020 2,340 $67.79 800 $69.38 $84.98Q1 2021 1,700 $73.53 800 $68.13 $83.91Q2 2021 1,200 $72.76 800 $66.88 $82.50Q3 2021 1,200 $72.97 300 $61.67 $74.53Q4 2021 900 $71.52 100 $60.00 $71.75Q1 2022 100 $71.58 100 $60.00 $71.75Q2 2022
Annual2019 2,338 $70.96 275 $60.91 $74.41 625 ($5.76) $71.87 511 ($4.79) $76.122020 2,363 $68.23 949 $68.95 $84.23 25 ($5.96) $77.002021 1,248 $72.84 498 $66.23 $78.402022 25 $1.59 25 $3.36 $71.75
Propane
Conway FEI
Term Volume (bbl/d) Price (C$/bbl) Volume (bbl/d) Price (C$/bbl)
Q3 2019 620 $34.60Q4 2019 560 $34.42Q1 2020 473 $32.55 550 $48.72Q2 2020 475 $32.54 550 $48.72Q3 2020 475 $32.54 550 $48.72Q4 2020 475 $31.92 550 $48.72Q1 2021Q2 2021Q3 2021Q4 2021Q1 2022Q2 2022
Annual2019 620 $35.112020 475 $32.38 550 $48.7220212022
Natural Gas (AECO, NYMEX & Chicago)
AECO Swaps (C$/GJ) AECO Costless Collars (C$/GJ) AECO Puts (C$/GJ) AECO Basis (C$/MMBtu)NYMEX Swaps (C$/MMBtu)
NYMEX Costless Collars (C$/MMBtu) NYMEX Puts (C$/MMBtu)
Station 2 Diff Swaps (C$/GJ)
TermVolume (GJ/d)
PriceVolume (GJ/d)
Floor Cap Volume (GJ/d)
Put Premium
StrikeVolume
(MMBtu/d)Price
Volume (MMBtu/d)
PriceVolume
(MMbtu/d)Floor Cap Volume
(MMBtu/d)Put
PremiumStrike
Volume (GJ/d)
Price
Q3 2019 55,000 $1.44 5,000 $1.05 $1.44 30,000 ($0.228) $1.36 23,500 ($1.91) 4,700 $3.54 9,400 $3.33 $3.63 9,400 ($0.208) $3.15 79,670 ($0.35)
Q4 2019 98,261 $1.67 13,315 $1.78 $2.04 38,315 ($0.252) $1.67 68,916 ($1.74) 18,800 $3.92 14,100 $3.32 $3.62 9,400 ($0.375) $3.77 29,087 ($0.38)
Q1 2020 108,297 $1.65 43,297 $1.77 $2.13 15,000 ($0.255) $1.70 59,499 ($1.78) 28,200 $3.64 $4.09 4,700 ($0.440) $3.87 10,000 ($0.40)
Q2 2020 100,000 $1.49 30,000 $1.13 $1.50 10,000 ($0.210) $1.32 61,100 ($1.88) 9,400 $3.30 9,400 $3.33 $3.63
Q3 2020 90,000 $1.51 25,000 $1.16 $1.44 5,000 ($0.170) $1.23 61,100 ($1.88) 9,400 $3.30 9,400 $3.33 $3.63
Q4 2020 94,946 $1.57 10,000 $1.49 $1.66 6,630 ($0.260) $1.77 64,267 ($1.88) 9,400 $3.33 $3.63 4,700 ($0.350) $3.51
Q1 2021 100,000 $1.78 15,000 $1.78 $2.26 10,000 ($0.260) $1.77 70,500 ($1.76) 4,700 ($0.400) $3.50
Q2 2021 80,000 $1.57 75,200 ($1.73) 4,700 ($0.400) $3.50
Q3 2021 65,000 $1.60 61,100 ($1.78) 4,700 ($0.400) $3.50
Q4 2021 55,000 $1.66 5,000 $1.75 $1.86 57,984 ($1.80) 4,700 ($0.400) $3.50
Q1 2022 35,000 $1.98 5,000 $1.92 $2.04 18,800 ($1.53)
Q2 2022 10,000 $1.63
Annual
2019 70,601 $1.70 7,096 $1.56 $1.96 33,356 ($0.230) $1.53 35,510 ($1.80) 8,254 $3.85 12,306 $3.38 $3.87 7,082 ($0.264) $3.36 72,865 ($0.35)
2020 98,279 $1.56 27,022 $1.42 $1.75 9,139 ($0.232) $1.54 61,498 ($1.85) 4,700 $3.30 14,074 $3.48 $3.86 2,350 ($0.395) $3.69 2,486 ($0.40)
2021 74,849 $1.66 4,959 $1.77 $2.16 2,466 ($0.260) $1.77 66,148 ($1.76) 4,700 ($0.400) $3.50
2022 11,123 $1.91 1,233 $1.92 $2.04 4,636 ($1.53)
32
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
•83 Tcf of gas-in-place
•Over 2,600 Hz well locations and 15 Tcfe of recoverable resource (two horizons only)
•Potential for development of four horizons
Aitken
Laprise/Sojer
Jedney
1. 4.5 wells/DSU/layer (300 m spacing), two layers developed, ranging from 5.0 - 9.0 Bcf/well, 90% land utilization2. 4.5 wells/DSU/layer (300 m spacing), four layers developed, ranging from 7.0 - 11.0 Bcf/well, 90% land utilization
Note: Based on management estimates, liquids converted at 1 bbl: 6 Mcf for gas equivalency, 40 bbl/MMcf liquids and 8% shrinkage
DSUs Base Case1 Upside Estimate2
#Hz Locations
#
Recoverable Resource
Tcfe
Hz Locations
#
Recoverable Resource
Tcfe
Aitken 152 1,225 8.3 2,449 19.0
Laprise/Sojer 113 919 4.6 1,837 12.9
Jedney 64 516 2.6 1,031 7.2
Total 329 2,659 15.4 5,318 39
19% Recovery Factor 47% Recovery Factor
Internal Estimate of Resource
10 km
Legend
1
2
3
4
33
Delivering on a Long-Term Strategy
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
Upper Montney Oil Window
Normally Pressured
Upper Montney Dry Gas
Alb
erta
B.C
.
Caribou
Umbach
Town
AltaresSeptimus
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 contour1600m
25 km
Upper Montney Over-Pressured
Liquids-Rich Fairway
0
100
200
300
400
500
600
700
800
Bla
ck S
wan
Pe
tro
nas
CN
Q
Sagu
aro
Can
bri
am
TOU
Po
lar
Star CR
SRX
AR
X
ECA
PP
Y
Cal
ima
CK
E
RD
S
LXE
TOD
D/P
OU
Ad
uro
CO
P
MU
R
KEL
PG
F
Pri
mav
era
NET
DSU
s
Liquids-rich gas
Largest Holder of Liquids-Rich Montney Rights
Dry gas Oil
34
0
200
400
600
800
1000
1200
1400
1600
1800
Jan
-14
Ap
r-1
4
Jul-
14
Oct
-14
Jan
-15
Ap
r-1
5
Jul-
15
Oct
-15
Jan
-16
Ap
r-1
6
Jul-
16
Oct
-16
Jan
-17
Ap
r-1
7
Jul-
17
Oct
-17
Jan
-18
Ap
r-1
8
Jul-
18
Oct
-18
Jan
-19
Ap
r-1
9
Cal
-D
ay A
vg (
MM
cf/d
)
North Montney Producers
Conoco
CNRL
Polar Star
ARC
Chinook
Kelt
Todd
Saguaro
Storm
BSE
Tourmaline
Canbriam
Painted Pony
Petronas
NEBC Growth Driven by Junior/Intermediate Producers
Note: Montney
Industry Investment• North Montney production peak at over 1.6 Bcf/d April 2018• Juniors and Intermediates represent ~55% of total North
Montney production, up from ~30% four years ago
Note: Competitor land positions based on public reports and geoSCOUT
20 km
McMahon turnaround
T-south outage
McMahon turnaround
35
Corporate Information
Executive Independent Reserve EvaluatorDavid Maddison President & Chief Executive Officer GLJ Petroleum Consultants
Marc Mereau Chief Operating Officer
Bruce Thornhill VP Exploration AuditorsMichael Wilhelm VP Finance & Chief Financial Officer KPMG
Christine Ezinga VP Strategy & Planning
Leanne Juneau VP Land Legal CounselBryan Lang VP Operations Norton Rose Fulbright
Diane Shirra VP Business Development
BankersCanadian Imperial Bank of Commerce
Directors Toronto-Dominion Bank
Jackie Sheppard Lead Director Business Development Bank of Canada
David Maddison President & Chief Executive Officer Royal Bank of Canada
Jim Buckee Independent Director National Bank of Canada
Evan Hazell Independent Director
Jim Nieuwenburg Azimuth Capital Management Head OfficeDavid Pearce Azimuth Capital Management 2700, Bow Valley Square IV
Robert Mellema Canada Pension Plan Investment Board 250 6th Avenue SW
Roy Ben-Dor Warburg Pincus LLC Calgary, Alberta
David Krieger Warburg Pincus LLC T2P 3H7
website: www.blackswanenergy.com
Phone: (403) 930-4400
Investor Information Contact
Christine Ezinga (403) 930-4440
VP Strategy & Planning [email protected]