liquids rich montney value |scale | growth...liquids‐rich montney 231,000 acres 100% working...
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Liquids Rich Montney Value | Scale | Growth
May 2020
2
FT ST JOHN
EDMONTON
MONTNEY
BRITISH COLUMBIA
ALBERTA
10 km
Liquids‐Rich Montney 231,000 acres
100% working interest
Overview – Well Positioned in a Challenging Market
1. At $1.85/GJ AECO, US$36/bbl WTI and $1.41 C$/US$; prior to hedging2. Bank facility of $325MM excludes $25MM accordion for additional syndicate participation; debt includes US$100MM of 9% notes maturing in 2024
3. North Montney Mainline connection to NGTL in service effective Feb 1, 2020
Positioned for Self Funding• Production maintained at 40,000 – 44,000 boe/d in 2020• EBITDA forecast of ~$102 MM in 20201 at recent strip• Low sustaining capital of ~$65 MM at current production levels
Managing Capital & Retaining Resilience• Unutilized bank facility: $180MM exiting Q1 20202• Hedges for 70% of gas & 65% of liquids for balance of 2020• Ability to defer long lead infrastructure capital
Optimizing Our Infrastructure Advantage• Operated gas plant processing capacity of 210 MMcf/d• A commitment to expand existing plant by midstream partner• Expanding liquids infrastructure to enhance netbacks
Delivering to Multiple Natural Gas Markets• Connected to NGTL3, Enbridge and Alliance pipelines• Able to direct 90% of sales gas to AECO in 2020 • Firm capacity to Empress and Dawn starting in 2021
Diversifying Revenues with Increased Liquids• Expect to produce 8,500 bbl/d of total liquids in 2020• Over 50% of liquids (4,500 bbl/d) is 60◦ API condensate• 1,500 bbl/d of propane to premium FEI overseas markets
Nig Creek Plant 2
North Aitken Plant 1
3
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2014 2015 2016 2017 2018 2019 2020E
Realized
Pric
ing ($/boe
)
Cash Flow ($
MM)
Cash Flow Realized Liquids Price Realized Gas Price
‐
100
200
300
400
500
2014 2015 2016 2017 2018 2019
Reserves (M
Mbo
e)
PDP PDNP + PUD Probable
$0
$5
$10
$15
$20
2014 2015 2016 2017 2018 2019 2020E
$/bo
e
Opex Transportation G&A Financing
Established Long Term Sustainability
Reserve Growth2
2020E Controllable Cash Costs: <$10/boe3
Inception to date 2P FD&A of $5.21/boe
Cash Flow1 vs. Commodity Prices
Controllable Cash Costs
Production Growth
Running less than one rig annually delivered:
>50% CAGR 2015 – 2020
Growing Cash Flow in 2020
0
5
10
15
20
25
30
35
40
45
2014 2015 2016 2017 2018 2019 2020E
Avg. Daily Produ
ction (m
boe/d)
1. Includes hedging gains/losses, gas converted to boe on 6:1 basis2. 2017 YE 2P reserves were reduced to reflect certain Lower Montney 2P reserves moved to contingent3. 2020E transportation includes $0.84/boe related to unutilized NMML transportation
4
2019 PDP Finding Cost ‐ A Leader Amongst Peers
0.0x
0.2x
0.4x
0.6x
0.8x
1.0x
1.2x
1.4x
1.6x
1.8x
Peer 1
Peer 2
Peer 3
Peer 4
Peer 5
Peer 6
Peer 7
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Peer 9
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Peer 11
2020
E Ca
sh Flow Recycle
Recycle Ratio1: 2020E Cash Flow Netback vs. 2019 PDP FD&A
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$2.00
$4.00
$6.00
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$14.00
$16.00
$18.00Pe
er 1
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Peer 8
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Peer 11
PDP FD
&A ($/boe
)
2019 PDP FD&A
BSE
BSE
Low Cost Leader• Low PDP FD&A costs provide resilience and flexibility in a low commodity price environment
Generating Economic Barrels• Low cost structure provides ability to maintain capital spending in the context of expected 2020 cash flow2
Source: Peters & Co., National Bank Financial and Black Swan Energy1. The recycle ratio looks at the cash flow we generate vs. the cost to add a barrel of reserves2. 2020E price deck: US$41.50/bbl WTI, 1.34 FX and $1.81/GJ AECO
5
89
93
113
1568
2019 Booked Locations (324)3
Developed ‐ Upper PUD ‐ Upper PRB ‐ UpperDeveloped ‐ Lower PUD ‐ Lower PRB ‐ Lower
Growth Plan Supported by Low Cost Reserves
1. GLJ January 1, 2020 price forecast, includes 1P FDC $0.55 B and 2P FDC $1.25 B2. Natural gas volumes converted to barrels of oil equivalent at 6,000 cubic feet per barrel (6 mcf = 1 boe)3. Developed = PDP & Non‐Producing Developed, PUD = Proved Undeveloped, PRB = Probable
2019 PDP adds replaced >250% of annual production2019 Year End Reserves
Net Present Value1 Before Tax
($MM)
Gas (MMcf)
NGLs (mbbl)
Total (mboe)2 0% 10%
PDP 468,044 19,768 97,775 1,063 733
Total proved 1,032,404 44,058 216,125 2,332 1,204
Proved + probable 2,206,101 94,176 461,859 5,879 2,073
Locations booked continue to focus on near term Upper Montney targets, leaving upside to unbooked zones
9.96
7.14 6.866.08
5.34 5.21
$0.00
$2.00
$4.00
$6.00
$8.00
$10.00
2014 2015 2016 2017 2018 2019
F&D ($
/boe
)
Inception to Date 2P F&D (including FDC)
Other Land Infr. D&C
21%
26%53%
2019
PDPProved UndevelopedProbable
6
7.18.1
11.8
8.9 8.77.9
10.5 10.7 10.3 109.8
10.1 10.2
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 88‐C 56‐C
2014 2015 2016 2017 2018 2019
Avg EU
R (Bcf/w
ell)
Upper Montney Hz ‐ Avg EUR by Pad
BSE EUR Last 65 Well Average
Demonstrated Track Record
Predictable Well Results• Average EUR: 9.4 Bcf since 2012 (82 wells)1
• Average EUR: 10 Bcf (last 65 wells)1
• Initial yield 40‐70 bbl/MMcf (50‐60% C5+)• Type curve IP30: 1,200 boe/d (25% liquids)
Multi‐Well Pad Development• 13 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. 5 additional Hz have been completed with minimal production history
10 km
Aitken Core Area
42‐D
Upper Montney Pad WellsCompleted Wells (Limited Production)
19‐E7‐H
54‐D
2‐C 22‐C
32‐C
52‐C
72‐C
92‐C
44‐C
Lower Montney + Pilot Wells
Legend
56‐C
88‐C
7
$0
$500
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$1.5
$2.0
$2.5
$3.0
$3.5
$4.0
$4.5
1 10 20 30 40 50 60 70 80
2013‐2014
2015 2016 2017 2018 2019
Cost per lateral m
Drillin
g Co
st (M
M)
Montney Hz Drilled
Black Swan Drilling CostCost per WellCost per m
$0
$1,000
$2,000
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$7.0
1 10 20 30 40 50 60 70 79
2013‐2014
2015 2016 2017 2018 2019
Cost per Ton
ne
Completion Co
st ($
MM)
Montney Hz Completed
Black Swan Completion Cost
Cost per WellCost per Tonne
Consistent Wellbore Costs
$1,000 per lateral metre
$1,000 per tonne
Continuous Optimization• Tested wells up to 2,700m length and 1.3 T/m• Plan to continue testing longer wells in 2020
Base Design For Development Plan$4 MM D&C and 10 Bcf per well
$1,200 per tonne
Established Cost Structure• Costs since 2018:
• $1,000/tonne completion• $1,000/metre drilling
• Base well design assumes 2,000m and 2,000T• Spud to RR averaging 11 days• Open hole frac average 27 hours per well
8
Compelling Economics: Type Curve Increased to 10 Bcf
Increased Type Curve to 10 Bcf• Based on >10 Bcf results over the last several years• Modelled D&C cost remains $4.0MM
Liquids Contribution• Total 400 mbbl per 10 Bcf well:
• 200 mbbl condensate (C5+) • 200 mbbl LPG (50% propane & 50% butane)
0
50
100
150
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250
0
1,000
2,000
3,000
4,000
5,000
6,000
7,000
0 60 120 180 240 300 360 420 480 540 600
C5+ (bbl/d)
Gas Rate (M
cf/d)
Normalized Days
Last 50 Wells vs Type Curve1
10 Bcf Type CurveAverage Gas200 mbbl C5+ Type CurveAverage C5+
1. C5+ includes lease & plant recoveries; C3/C4 yield from the plant is additional and not shown2. FX 1.373. C$2.00/GJ AECO, US$40/bbl WTI & FX 1.374. Full cycle represents point forward full cycle and does not include the historical cost of land but does include full plant infrastructure
16%
54%
104%
5%
27%
54%
0%
10%
20%
30%
40%
50%
60%
70%
80%
90%
100%
110%
C$1.50/GJ AECOUS$30/bbl WTI
C$2.00/GJ AECOUS$40/bbl WTI
C$2.50/GJ AECOUS$50/bbl WTI
IRR
10.0 Bcf Type Curve Economics2
Half Cycle
Full Cycle
Aitken Montney Economics3
Half Cycle Full Cycle4
Gas EUR Bcf 10.0 10.0Liquids EUR mbbl 400 400DCET $MM 4.5 4.5Infrastructure $MM 0 1.5Netback (Year 1) $/boe 12.55 10.29IRR % 54% 27%NPV10 $MM 5.2 3.1Payout Years 1.7 3.0F&D $/boe 2.35 3.10Recycle Ratio 3.8 2.9Break‐Even @ US$40/bbl $/GJ 0.98 1.40
9
0
20
40
60
80
100
120
140
160
180
200
220
Jan‐16 Jul‐16 Jan‐17 Jul‐17 Jan‐18 Jul‐18 Jan‐19 Jul‐19 Jan‐20
Gas Produ
ction (M
Mcf/d)
Inlet Gas (MMcf/d) Inlet Capability (MMcf/d)
Owned & Operated Infrastructure: Performance with Low Costs
North Aitken operating at >98% run time
Plant Capacity• North Aitken plant: >98% run time since commissioning• Nig Creek on‐stream Sept 2, 2019
• Consistent performance despite NMML related delays• Producing above nameplate post NMML (onstream Feb 2020)
• BSE plants opex would be $2.80/boe without the BC Carbon Tax, demonstrating operational excellence in line with top AB producers
Capital pre‐spent to facilitate Nig Creek deep cut expansion
Nig Creek Plant
Demonstrated Plant Performance
North Aitken Commissioned
Nig Creek Commissioned (constrained pre‐NMML)North Aitken
Expansion
North Aitken Final Compression
NMML on‐stream
Source: National Bank Financial and Black Swan. Peers include: AAV, ARX, BIR, CR, KEL, NVA, PEY, PONY, SRX, TOU, VII
$0.00
$2.00
$4.00
$6.00
$8.00
$10.00
Peer 1
Peer 2
Peer 3
Peer 4
Peer 5
Peer 6
Peer 7
BSE
Peer 8
BSE Plan
ts
Peer 9
Peer 10
Peer 11
2020
E Ope
ratin
g Co
sts ($/bo
e)
Top Tier Costs Support Long Term Sustainability
10
0
10
20
30
40
50
60
Jan‐16 Jul‐16 Jan‐17 Jul‐17 Jan‐18 Jul‐18 Jan‐19 Jul‐19 Jan‐20
Total Liquids Yields (bb
l/MMcf Raw
)
Black Swan Aitken & Nig Creek Plants Liquids Yield
LPG Condensate
Black Swan Liquids Yields at North Aitken & Nig Creek Plants
Avg LPG1 Yield: 20 bbl/MMcf
Avg Condensate Yield: 23 bbl/MMcf
Optimizing Recoveries• Aitken lands demonstrate consistent condensate yields
• Propane recovery optimized by managing operating temperatures
• Corporate liquids ratio will increase with increased operated vs third party processing capacity
• Long term expected liquids recovery: • 30‐50 bbl/MMcf (varies based on propane prices)
1. LPG includes propane (C3) and butane (C4)2. Avg Plant Temps represents North Aitken and the average of both North Aitken and Nig Creek post Sept 2019
‐40
‐35
‐30
‐25
‐20
‐15
‐10
‐5
00
5
10
15
20
25
30
35
40
Jan‐16 Jul‐16 Jan‐17 Jul‐17 Jan‐18 Jul‐18 Jan‐19 Jul‐19 Jan‐20
Refrig Tem
p (Celcius)
LPG Yield (b
bl/M
Mcf Raw
)
Liquid Yields vs. Average2 Plant Temp
LPG Avg Plant Temps Upper Montney Initial Lease Condensate (bbl/MMcf)
Black Swan Gas Plants
Excludes Plant C5+ of 9 bbl/MMcf
11
Leveraging Off Successful Infrastructure Execution
1. The AltaGas Ridley Island Propane Export Terminal
Low Cost Expandability• Future deep cut expansions:
• Nig Creek (2021): +18 mboe/d (Phase B)• North Aitken (TBD): +16 mboe/d (Phase B)
Core Infrastructure In Place210 MMcf/d capacity at operated plants
Expandable to 360 MMcf/d
North Aitken PlantNig Creek Plant
Strategic Liquids Handling• Eliminated 4,000 bbl/d of trucking with pipeline to the AltaGas North Pine facility• Propane exports to FEI markets via RIPET1 provided ~$10/bblpremium in Q4/19• Pursuing regional condensate infrastructure to further reduce trucking costs
Infrastructure InvestmentQualified for $37MM of BC infrastructure
credits; $13MM received to date
12
2020 Guidance: Steady Production Setting up 2021 Growth
• Drilling & completions capital budget: • Wells: 18 Hz drills, 11 completions
• Infrastructure capital budget: • Wellsite & pipeline tie‐ins• Produced water facility
• Growth capital: • Nig Creek deep cut expansion
1. Based on annual pricing of $1.85/GJ AECO, US$36/bbl WTI and $1.41C$/US$, Edm C5+ 95% of WTI, C4 39% WTI2. Bank facility excludes $25 MM accordion for additional syndicate participation; $31 MM allocated to LCs; term notes have 9% coupon and mature Jan 2024
2020 GuidanceDec 20191 Mar 2020
Production (boe/d)Average 40,000 – 44,000 40,000 – 44,000Exit 40,000 – 44,000 40,000 – 44,000
Capital ($MM) $90 ‐ $110 $90 ‐ $110Cash flow ($MM) $95 ‐ $105 $75 ‐ $85Exit Net Debt ($MM) $280 ‐ $290 $300 ‐ $310
2020 Capital Program
Exit 2020 Balance sheet strength2:~$145MM capacity on $325MM bank facility
US$100MM of 7‐year term notes
$55 ‐ $60MM
$15 ‐$20MM
$20 ‐ $30MM
10 km
87‐C
36‐F
7‐G96‐C
2020 guidance updated for pricing, however the annual program may be adjusted in response to ongoing commodity price volatility in the market
13
Low Sustaining Capital
1. Capital efficiency of $5,400/boe/d 2. Assumes production is held flat at current rate3. $2.00/GJ AECO & US$40/bbl WTI4. 2B expansion adds ~18,000 boe/d for a gross cost of $110MM ($55MM
net to Black Swan)
•Well performance and cost structure provide for low sustaining capex requirements1
•At 42,000 boe/d2• Sustaining capital: $65 MM • Cash flow at long term prices3: $109 MM
• Free cash flow: $44MM• Planned Nig Creek expansion (2B)4 reduces sustaining capital to 50% of total cash flow
0
10,000
20,000
30,000
40,000
50,000
60,000
70,000
2019E 2020E 2021E 2022E 2023E
Prod
uctio
n (boe
/d)
Expansion OptionalityOption for
continued growth Building Capacity in Stages
Nig Creek (2A): 42,000 boe/d$65MM sustaining capex; $44 MM FCF3
Nig Creek (2B) 2021: 60,000 boe/d$90MM sustaining capex; $86 MM FCF3
• Execution strategy offers optionality at each stage for:• Free cash flow generation with flat production • Future growth
•Growth is underpinned by firm capacity for gas and liquids; can adjust pace to commodity prices•Well and pipeline licenses in place to support program through 2021
Performance Driven
Nig Creek expansion would fill NMML, taking advantage of $8.3MM/yr in unutilized transportation
0%
50%
100%
150%
200%
250%
300%
Peer 1
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BSE
Peer 9
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Peer 11
2020 Sustaining Capex as % of Total Cash Flow
Source: National Bank Financial and Black Swan Energy
14
0
50
100
150
200
250
300
350
Egress Processing
MMcf/d
Long Term Processing vs. Egress4
Connection to NGTL through NMML: Advancing Diversification
Egress Enables Netback Optimization• Access to egress on all three Canadian gas transmission systems• Option to flow up to 90% of 2020 volumes on NGTL• Additional market access beyond AECO
• 50 MMcf/d service to Empress (Q2/21) • 24 MMcf/d service to Dawn (Q4/21)3
British Columbia
Vancouver
Fort St. John
AllianceEnbridgeNGTL1
Existing Pipelines
North Montney Mainline
Access to Diverse Liquids Markets• Sales to FEI2 pricing with propane exports via RIPET
Owned & operated processing capacity supported by long term commitments
RIPET toFEI2
NGTL
Enbridge
McMahon
Nig Creek Expansion (2B)
North Aitken
Nig Creek
1. NGTL is part of the TC Energy pipeline system2. Far East Index3. Dawn deliveries utilize Empress capacity to achieve full path service from AECO4. Excludes 60 MMcf/d commitment to future Enbridge Spruce Ridge Project; timing TBDNote: Unutilized tolls: $1.1 MM/month post Plant 2A; $0.5MM/month post Plant 2B
15
0.0
1.0
2.0
3.0
4.0
5.0
6.0
2016 2017 2018
GHG Efficiency (gCO
2e/M
J)
Black Swan North Montney Peer Avg
Demonstrated Environmental Leadership
• Top decile LMR2 among all BC oil and gas producers• Recycled 100% of our produced water since June 2014•Water license supports 100+ Hz wells per year3
• >2.2 MMbbl of fresh water storage capacity constructed•Utilizing technology to reduce our carbon footprint
• Solar power at well pads•Waste heat recovery at plant to reduce GHG (greenhouse gas emissions) by 10,000 tonne/year• Upside with future access to hydro electric power
• CleanBC Industrial Incentive Program:• 2019: Central water processing facility award• 2020: Application for waste heat recovery & carbon capture study
“Off the grid” ‐ Solar panels provide power at well pad sitesMinimizing disturbance – multiple pipelines installed concurrently
1. GHG Efficiency as measured from wellhead to sales (including sustaining D&C GHG) on Black Swan facilities2. LMR (Liability Management Rating)3. Through Dec 31, 2021, with renewal provisions
GHG Efficiency with Growth1
Using technology to deliver leading GHG efficiencies
16
Our Ideals In Action
Health & Safety• Committed to ensuring a safe and healthy workplace and minimizing the impact on the environment
• Integrated Safety Management System• Low annual TRIF1
• Certificate of Recognition audit completed in 20192 with score of 92%
1. TRIF (Total Recordable Incident Frequency) as measured by incident per 200,000 man hours2. From the Alberta Association For Safety Partnerships 3. Jackie Sheppard (Lead Director), Jim Buckee and Evan Hazell
Graduation ceremony of the First Nations Training Initiative
Governance• Focused on long term value creation for investors• 3 of 8 directors are independent including the Lead Director3
• Women in executive roles:• Board of Directors: 13%• Senior Executive: 40%
• Coordinated First Nations Training Initiative• Active corporate giving
• Raised over $430k for charitable causes since inception
0.55 0.59 0.96 0.83 0.00 0.35 0.61 0.380.00
0.20
0.40
0.60
0.80
1.00
1.20
1.40
1.60
0.00
0.20
0.40
0.60
0.80
1.00
1.20
1.40
1.60
2012 2013 2014 2015 2016 2017 2018 2019
Work Hou
rs M
illions
Yearly In
cide
nts F
requ
ency
TRIF and Work Hours
TRIF Workhours
17
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 delineation supported by offset competitor activity
•>2,600 Hz locations provides long term visibility
•Exposure to increased liquids in the Lower Montney•Remaining acreage & landing zones provide potential to:
•Backstop long term free cash flow generation; or• Increase peak production
Black Swan is now the 4th largest private producer of oil and gas in
Canada
Aitken Core Development
Area
Laprise
Jedney
Nig
Birch
Gundy
18
$0
$2
$4
$6
$8
$10
$0.0
$2.0
$4.0
$6.0
$8.0
$10.0
$12.0
0
2
4
6
8
10
12
14
0%
20%
40%
60%
80%
100%
Strength Across Multiple Factors Drives Long Term Profits
$3.97
80%
Source: Internal estimates, National Bank Financial & company reports; peer group includes: AAV, ARX, BIR, CR, KEL, NVA, PONY, Saguaro, SRX, TOU, VII
Infrastructure Advantage2020E Operating Costs ($/boe)2
Natural Gas ContributionGas Weighting (%) 2020E
BSE
BSE
Well Performance
10
$4.5
Average EUR Bcf (Wells Drilled Last 36 Mos.)1
2020E DCET Cost ($MM)
Competitive Capital Costs
BSE
BSE
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 Facilities3. Revenue, Royalty, Opex, G&A, Interest based on 5 year plan at $2.00/GJ AECO & US$40/bbl WTI4. Infrastructure costs averaged across drilling for a 10 year production plateau
Revenue $17.15Royalty 1.05Opex + transport 6.70G&A + interest 1.70
Cash Netback $7.70
Half cycle F&D $2.35Infrastructure4 $0.80
Full cycle F&D $3.15
Recycle Ratio 2.4x
Forward Economics3Full Cycle ($/boe)
19
Appendix
Liquids Rich Montney Value | Scale | Growth
20
Black Swan Energy Executive Team
David Maddison, P.Eng.David is President, CEO and founder of Black Swan Energy.He has 35+ years of industry experience focused onconventional and resource plays in Western Canada. Priorto Black Swan, he was with Talisman Energy where hemanaged multi‐disciplinary teams in the WCSB, withproduction 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 BlackSwan Energy. He has 35+ years of experience in the oil andgas industry, both domestically and internationally. Prior toBlack Swan, Marc worked at Talisman Energy, where heheld progressively larger roles including Senior VicePresident of Western Operations for North America.
Michael Wilhelm, B.Comm., CPA, CGAMike is Vice President, Finance and CFO and a co‐founder ofBlack Swan Energy. He has 30+ years experience in the oiland gas industry, with an extensive background in bothprivate and public financings in Canadian and U.S. markets.Mike was involved as a founder and in the ongoing fundingof Equatorial Energy and Espoir Exploration. He was alsoinvolved with the IPO of Resolute Energy Inc. through theRTO of Equatorial Energy Inc.
Bruce Thornhill, P.GeoBruce is Vice President, Exploration of Black Swan Energy.He has 35+ years of experience in the energy industryfocused on conventional and resource play exploration anddevelopment, primarily in the western Canadian DeepBasin. Prior to joining Black Swan, he was a member of thesenior management team at TAQA North, first as VP ofExploration and later as VP of the North Asset managing anannual capital budget of $200MM. Bruce currently serveson the Board of Kaden Energy.
Bryan Lang, P.Eng.Bryan is Vice President, Operations of Black Swan Energy.He has 30+ years of experience in the energy industryfocused on Western Canadian operations. He started hiscareer at Chevron Canada and at growth oriented operatorsNorthrock Resources and Peyto Exploration. He played alead role in the development of horizontal multistageresource plays, and has assembled highly efficient teamsfocused on safe, low cost operations.
Leanne Juneau, B.Comm.Leanne is Vice President, Land, Corporate Secretary and aco‐founder of Black Swan Energy. She has 20+ yearsexperience negotiating and executing exploration anddevelopment agreements and strategic corporate and assetacquisitions and dispositions within Western Canada. Shehas 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 BlackSwan Energy. She has 35+ years of experience in theenergy industry focused on exploitation and developmentof both conventional and resource plays throughoutWestern Canada. Most recently she was VP Montney GasDevelopment and VP Reserves and Strategic Projects atPengrowth Energy Corporation.
Christine Ezinga, B.Comm., CFAChristine is Vice President of Strategy & Planning at BlackSwan Energy. She has 20+ years of diverse capital marketsexperience in finance, investor relations and businessdevelopment including corporate and asset level M&Adeals. 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 PetroleumAcquisition and Divestiture Association.
21
Black Swan Energy Board of Directors
David Maddison, P.Eng.David is President, CEO and founder of Black Swan Energy. He has 35+ years ofindustry 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 capitalbudgets of $1 billion.
Jackie Sheppard, Lead DirectorJackie is a Founder of Black Swan and was formerly the Executive Vice‐President,Corporate and Legal and Corporate Secretary for Talisman Energy Inc. She served asSecretary to the Board responsible for Corporate Projects and Acquisitions,Communications and Investor Relations. She currently serves on the Boards of EmeraInc. and Seven Generations and is also a director of Alberta Investment ManagementCorporation (AIMCo). Jackie is a Rhodes Scholar, having received an HonorsJurisprudence, Bachelor of Arts and Master of Arts from Oxford University. She earnedher Bachelor of Laws (Honors) from McGill University and holds an honorary Doctor ofLaws fromMemorial University.
Dr. James BuckeeJim is a Founder of Black Swan Energy. In September 1991 Jim was appointedPresident and Chief Operating Officer for BP Canada Inc. and in May 1993 he wasappointed President and Chief Executive Officer of Talisman Energy Inc. (formerly BPCanada). When Jim retired, in October 2007, Talisman was producing over 500,000boe/d. He also serves on the boards of Magma Global and M‐Flow and sits on theadvisory Board of Azimuth Capital Management. Jim holds a BSc Honours in Physicsfrom the University of Western Australia and in 1970 he received his PhD inAstrophysics 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 apetroleum engineer and as an investment banker. At present, he serves as a Directorof non‐profit and community organizations Opera America, Calgary Municipal LandCorporation and Calgary YMCA. From 1998 to 2011, he acted as a managing directorat several financial institutions including HSBC Global Investment Bank and RBCCapital Markets. Evan holds a Bachelor of Applied Science degree from Queen'sUniversity, a Master of Engineering degree from the University of Calgary, and anMBA degree from the University of Michigan.
Robert MellemaRobert has been with the Canada Pension Plan Investment Board (CPPIB) since2008 and is a Senior Principal in the Natural Resources Group. He is a member ofCPPIB’s Sustainable Investing Committee and serves as a Director on the boards ofLivingston International Inc. and Wolf Midstream and has previously been involvedin CPPIB’s investments in Teine Energy and Seven Generations Energy. Robertholds a MBA from the Wharton School at the University of Pennsylvania where hewas a Palmer Scholar and a Bachelor of Commerce degree from Queen’sUniversity, where he graduated with first class honours.
Roy Ben‐Dor, MBARoy joined Warburg Pincus in 2011 and previously worked at McKinsey &Company in New York. He is a Director of Artis Exploration Ltd, Black Swan Energy,Osum Oil Sands and Zenith Energy and also works with Navitas MidstreamPartners. Roy received a B.A. cum laude in Psychology and Economics withDistinction from Duke University, a J.D. magna cum laude from Harvard LawSchool and an MBA with High Distinction (“Baker Scholar”) from Harvard BusinessSchool.
Dave PearceDave is Deputy Managing Partner with Azimuth Capital Management. During his35+ years in the energy sector, he has worked in a variety of technical andexecutive roles in Exploration, Production and Corporate Development as well asan Independent Director in Canada and internationally. Dave was President andCEO of Northrock Resources, an intermediate Canadian E&P company. He is also aDirector of Altex Energy, Baytex Energy, Kaden Energy, Kaisen Energy, KarveEnergy and TimberRock Energy.
Jim NieuwenburgJim is an Operating Partner at Azimuth Capital Management. He has 35+ years ofexperience in the energy sector and 20+ years of executive management andcorporate governance experience. Previously, he has held positions at PetrometResources (CEO), Norcen Energy (Vice President) and Amoco Canada. Jim alsoserves as a Director on the boards of Corex Resources, Monolith Materials, andRecover Energy Systems and is Chairman on the board of Rifco Inc.
22
2019 2019 2018 2018 2017 2017Full Year Q4 Q3 Q2 Q1 Full Year Q4 Q3 Q2 Q1 Full Year Q4 Q3 Q2 Q1
ProductionGas (mcf/d) 140,948 189,174 139,263 114,449 120,169 121,614 120,960 125,401 121,914 118,105 88,559 116,138 85,769 66,194 85,832NGL (bbl/d) 5,621 7,559 5,283 4,439 5,180 5,176 5,085 5,249 5,449 4,917 3,166 4,838 3,501 1,868 2,427Total (boe/d) 29,112 39,088 28,494 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 71,553 30,601 10,997 7,019 22,936 109,356 15,799 31,949 29,172 32,445 74,435 23,425 14,130 14,241 22,639EBITDA2 59,134 15,730 11,902 7,617 23,885 98,666 19,152 24,452 24,024 31,038 84,282 30,855 19,631 13,074 20,722Funds from operations 43,15 10,911 7,675 3,947 20,616 82,786 15,754 19,916 19,994 27,122 71,025 27,132 16,347 9,705 17,841Capex (incl. A&D) 192,586 19,878 65,121 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) 17,277 17,277 27,501 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 139,231 139,231 120,000 82,808 7,494 ‐ ‐ 91,707 91,420 77,541 66,147 66,147 48,759 13,091 ‐Term Notes 131,026 131,026 131,566 132,439 133,902 133,826 133,826 133,517 133,466 133,829 132,275 132,275 128,513 129,513 129,590Total Net Debt 287,534 287,534 279,067 222,474 177,542 141,771 141,771 233,883 224,128 222,514 203,110 203,110 200,448 166,520 121,450Total Credit Facility 350,000 350,000 300,000 300,000 275,000 275,000 275,000 300,000 300,000 270,000 270,000 270,000 250,000 200,000 200,000
Netback Summary ($/boe)Net Revenue 14.63 16.07 11.61 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) (0.13) (2.50) 0.99 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 (0.78) (0.97) (0.52) (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 (4.20) (3.76) (4.09) (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 (2.92) (2.83) (2.80) (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 6.60 6.01 5.19 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 (1.07) (1.66) (0.69) (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 0.03 0.02 0.04 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 (1.50) (1.34) (1.61) (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 4.06 3.03 2.93 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/losses
23
Type Curve Assumptions
1. Pricing assumes deliver to AECO via Black Swan’s NMML commitment2. FX rate of C$1.37/US$ applied to US$WTI prices3. Economics include equip & tie‐in costs of $0.5 MM/well for total well DCE&T costs of $4.5 MM4. Black Swan pays BC Crown royalties calculated on a sliding scale for gas based on price and production rate & fixed percentage
of revenue for liquids 5. Pricing relative to C$WTI: C5+: 84%, C4: 24%, C3: 8% at US$40/bbl oil (realizations include price offsets for transportation &
terminal fees; trucking of $5.00/bbl included in opex & transportation)6. Opex & transportation represent the average cost during the first 12‐months
AssumptionsD&C Cost ($MM, excl. $0.5 MM tie‐in) $4.0EUR (Bcf) 10.0IP30 ‐ Total (boe/d) 1,210
Heat Content (MMBtu/mcf) 1,150Liquids Yield (bbl/MMcf) 40Royalty Drilling Credit ($ MM) $1.05 Opex & Transportation – 1st Year ($/boe) $6.04Opex & Transportation – Full life ($/boe) $7.13Full Cycle – Infrastructure ($/boe) $0.75Full Cycle – G&A ($/boe) $0.75
24
4,600
5,100
5,600
6,100
6,600
7,100
7,600
2014 2015 2016 2017 2018 20191400
1600
1800
2000
2200
2400
Feet
Metres
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 20190
20
40
60
80
100
Feet
Metres
Stage Spacing
330
430
530
630
730
830
930
2014 2015 2016 2017 2018 20190.5
0.7
0.9
1.1
1.3
1.5
lbs/ft
tonn
e/m
Proppant Concentration
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
7‐H Pad Average19‐E Pad Average54‐D Pad Average22‐C Pad Average92‐C Pad Averagec‐2‐C Pad Average72‐C Pad Average42‐D Pad Average32‐C Pad Average
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 Area
10.5 Bcf
9.0 Bcf
7.5 Bcf
Type Curves
Black Swan’s type curves reflect a restricted draw down
42‐D
72‐C
Normalized Days1. 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&C
32‐C
Lower Montney + Pilot Wells
26
North Montney Mainline Overview
• NMML construction commenced Aug 2018• On‐stream February 1, 2020• Production flows onto the NGTL system• Part of TC Energy’s multi‐billion dollar expansions to improve system access to export markets
• Provides Black Swan with potential LNG optionality• LNG Canada’s1 Coastal Gas Link project
Eastern and Western Market Potential
Source: CER filings
NGTLBritish Columbia
Vancouver
Kitimat
Fort St. John
1. LNG Canada announced positive FID Oct 2, 2018
North Montney Mainline
‐
200
400
600
800
1,000
1,200
1,400
1,600
1,800
2,000
Feb 2020 Apr 2020 Apr 2021 Apr 2022
MMcf/d
NMML Producer Ramp Up
Expansion FT‐R
Shipper J
Shipper K
Shipper A
Shipper C
Shipper F
Shipper E
Shipper D
Shipper B
BSE
Progress
27
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) and planned expansions of both facilities
Announced October 2018• Investment by AltaGas for 50% WI in certain existing and future natural gas processing plants of Black Swan:• $136MM in 2018 • ~$50MM in Q4/19
• The North Aitken Processing Facilities1 will have ~210 MMcf/d of processing capacity• Potential to increase up to 360 MMcf/d with future expansions
• No take or pay•Black Swan to remain operator of the gas processing facilities• Strategic liquids handling
• 56 km of new LPG pipeline to bring Black Swan C3/C4 to the AltaGas North Pine Fractionation Facility
• Propane exports to FEI markets via the AltaGas Ridley Island Export Terminal (RIPET) 56km of new
LPG pipeline
AltaGas TownsendGas Plant
AltaGas North Pine Fractionation
Facility
North Aitken Processing Facilities1
Expandable to 360 MMcf/d
10 km
28
NGTL
ENBRIDGE
ALLIANCE
NORTHERNBORDER
TC ENERGY MAINLINE
GREAT LAKESIROQUOIS
VIKING
ROVER
NEXUS
FOOTHILLS
GTN
VECTOR
CHICAGO
DAWN
AECO
SKAB
BC
MB ON
QC
STN 2
ROCKIES EXPRESSRUBY
Delivering Liquids & Natural Gas to Diverse Markets
EMPRESS
ATP
RIPET to FEI
Black Swan’s Physical Markets• Connected to Alliance, Enbridge & NGTL pipeline systems• NGTL provides access to AECO and markets downstream of TC Energy in eastern Canada and the U.S.• RIPET exports to Asian propane markets commenced May 2019 and provides access to FEI pricing
29
Hedge Position & Pricing Summary
At Apr 16, 2020
Condensate & ButaneC$WTI Swaps
(C$/bbl)C$WTI Costless Collars
(C$/bbl) C$WTI Long Puts (C$/bbl) C$WTI Long Calls (C$/bbl) C$ WTI Differential
Term Volume (bbl/d) Price Volume
(bbl/d)Volume (bbl/d)
Put Premium Strike Volume
(bbl/d)Call
Premium Strike Volume (bbl/d) PriceFloor Cap
Q1 2020 2,332 $68.41 1,100 $68.64 $83.46 100 ($5.96) $77.00 264 $1.13 $84.00 1,582 ($3.35)Q2 2020 2,407 $67.96 1,100 $68.64 $83.46 400 $1.13 $84.00 1,150 ($4.30)Q3 2020 2,340 $67.18 800 $69.38 $84.98 450 ($5.72)Q4 2020 2,340 $66.89 800 $69.38 $84.98 450 ($5.72)Q1 2021 1,800 $72.39 800 $68.13 $83.91 100 ($7.25) $50.00 Q2 2021 1,400 $71.44 800 $66.88 $82.50Q3 2021 1,500 $70.84 300 $61.67 $74.53Q4 2021 1,300 $70.06 100 $60.00 $71.75Q1 2022 200 $62.29 600 $58.58 $70.31Q2 2022 100 $53.00 500 $58.30 $70.02Q3 2022 100 $53.00 500 $58.30 $70.02Q4 2022 100 $53.00 200 $53.75 $65.63
Annual2020 2,355 $67.61 949 $68.95 $84.23 25 ($5.96) $77.00 165 $1.13 $84.00 905 ($4.24)2021 1,499 $71.27 498 $66.23 $78.40 25 ($7.25) $50.002022 125 $56.68 449 $57.88 $69.05
Propane
Conway FEI
Term Volume (bbl/d) Price (C$/bbl) Volume (bbl/d) Price (C$/bbl)
Q1 2020 473 $32.55 750 $45.99Q2 2020 475 $32.54 750 $45.99Q3 2020 475 $32.54 750 $45.99Q4 2020 475 $31.92 750 $45.99Q1 2021 400 $36.84Q2 2021 400 $36.84Q3 2021 400 $36.84Q4 2021 400 $36.84Q1 2022Q2 2022Q3 2022Q4 2022
Annual2020 475 $32.38 750 $45.992021 400 $36.842022
Natural Gas (AECO, NYMEX & Chicago)AECO Swaps
(C$/GJ) AECO Costless Collars (C$/GJ) AECO Puts (C$/GJ) AECO Long Calls ($C/GJ)AECO Basis (C$/MMBtu)
NYMEX Swaps (C$/MMBtu)
NYMEX Costless Collars (C$/MMBtu) NYMEX Puts (C$/MMBtu)
Station 2 Diff Swaps (C$/GJ)
Term Volume (GJ/d) Price Volume
(GJ/d)Floor Cap Volume
(GJ/d)Put
Premium Strike Volume (GJ/d)
Call Premium Strike Volume
(MMBtu/d) Price Volume (MMBtu/d) Price Volume
(MMbtu/d)Floor Cap Volume
(MMBtu/d)Put
Premium Strike Volume (GJ/d) Price
Q1 2020 103,077 $1.67 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 51,813 ($0.31)Q2 2020 120,000 $1.52 30,000 $1.13 $1.50 10,000 ($0.210) $1.32 6,813 ($0.121) $1.58 51,648 ($1.92) 9,400 $3.30 14,100 $3.08 $3.45Q3 2020 110,000 $1.54 25,000 $1.16 $1.44 5,000 ($0.170) $1.23 59,516 ($1.88) 9,400 $3.30 14,100 $3.08 $3.45Q4 2020 114,946 $1.60 15,000 $1.52 $1.87 6,630 ($0.260) $1.77 62,684 ($1.89) 21,916 $3.21 $3.93 4,700 ($0.350) $3.51 Q1 2021 110,000 $1.76 15,000 $1.78 $2.26 10,000 ($0.260) $1.77 65,800 ($1.78) 28,200 $3.20 $4.06 4,700 ($0.400) $3.50 Q2 2021 100,000 $1.60 5,000 $1.90 $2.22 70,500 ($1.74) 4,700 $2.99 9,400 $2.86 $3.41 4,700 ($0.400) $3.50 Q3 2021 85,000 $1.64 61,100 ($1.78) 9,400 $2.86 $3.41 4,700 ($0.400) $3.50 Q4 2021 70,000 $1.67 15,000 $1.87 $2.16 57,984 ($1.80) 14,100 $3.01 $3.54 4,700 ($0.400) $3.50 Q1 2022 45,000 $1.94 30,000 $1.96 $2.20 18,800 ($1.53) 4,700 $3.20 $4.03Q2 2022 50,000 $1.74 5,000 $1.80 $2.05 14,100 ($1.32)Q3 2022 25,000 $1.85 10,000 $1.83 $2.11 14,100 ($1.27)Q4 2022 10,000 $1.85 10,000 $1.93 $2.38 9,400 ($1.16)
Annual2020 112,008 $1.58 28,279 $1.43 $1.78 9,139 ($0.232) $1.54 1,694 ($0.121) $1.58 58,352 ($1.86) 4,700 $3.30 19,570 $3.32 $3.82 2,350 ($0.395) $3.69 12,883 ($0.31)2021 91,123 $1.67 8,726 $1.84 $2.21 2,466 ($0.260) $1.77 63,817 ($1.77) 1,172 $2.99 15,220 $3.05 $3.74 4,700 ($0.400) $3.502022 32,384 $1.84 13,685 $1.92 $2.20 14,074 ($1.35) 1,159 $3.20 $4.03
30
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
TcfeAitken 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
31
Strategically Situated in the Fairway
Upper Montney Oil Window
Normally Pressured
Upper Montney Dry Gas
Alberta
B.C.
Caribou
Umbach
Town
Altares Septimus
Groundbirch
Swan
Parkland
Aitken
Beg
Jedney Laprise
Montney Hz post 2013
Legend
Montney Hz
Black Swan land
Liquids‐rich gas window
Dry gas window
Oil window (>75 bbl/MMcf)
Montney TVD contour1600m
25 km
Upper Montney Over‐Pressured Liquids‐Rich Fairway
0
100
200
300
400
500
600
700
800
TOU
Black Sw
anPe
tron
asCN
QSagu
aro
Canb
riam CR SRX
ARX
OVV
PONY
Calim
aRD
SLXE
TODD
/POU
Aduro
COP
MUR
KEL
PGF
Prim
avera
NET
DSU
s
Liquids‐rich gas
Second Largest Holder of Liquids‐Rich Montney Rights
Dry gas Oil
Repeatable deliverability• Highly over‐pressured reservoir 13‐16 kPa/m
Low cost structure• Shallow target, surface access and drilling characteristics• Owned & operated infrastructure
Liquids‐rich• Total liquids of 30‐50 bbl/MMcf (>50% C5+)1
Scalable• Large contiguous position
32
0.0
0.2
0.4
0.6
0.8
1.0
1.2
1.4
1.6
1.8
2.0
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
Oct‐17
Jan‐18
Apr‐18
Jul‐1
8
Oct‐18
Jan‐19
Apr‐19
Jul‐1
9
Oct‐19
Jan‐20
Cal ‐Da
y Av
g (Bcf/d)
North Montney Producers (2011 to present)
Petronas Painted Pony Tourmaline Black SwanPacific Canbriam Storm Saguaro KeltTodd Conoco ARC CNRLYoho
Black Swan is the 4th Largest North Montney Producer
Industry Investment• North Montney production peak at over 1.8 Bcf/d Feb 2020
Note: Competitor land positions based on public reports and geoSCOUT
20 km
McMahon turnaround
T‐south outage
McMahon turnaround
33
Corporate Information
Executive Independent Reserve EvaluatorDavid Maddison President & Chief Executive Officer GLJ Petroleum ConsultantsMarc Mereau Chief Operating OfficerBruce Thornhill VP Exploration AuditorsMichael Wilhelm VP Finance & Chief Financial Officer KPMG Christine Ezinga VP Strategy & PlanningLeanne Juneau VP Land Legal CounselBryan Lang VP Operations Norton Rose FulbrightDiane Shirra VP Business Development
BankersCanadian Imperial Bank of Commerce
Directors Toronto‐Dominion BankJackie Sheppard Lead Director Business Development Bank of CanadaDavid Maddison President & Chief Executive Officer Royal Bank of CanadaJim Buckee Independent Director National Bank of CanadaEvan Hazell Independent Director Alberta Treasury BranchesJim Nieuwenburg Azimuth Capital ManagementDavid Pearce Azimuth Capital Management Head OfficeRobert Mellema Canada Pension Plan Investment Board 2700, Bow Valley Square IVRoy Ben‐Dor Warburg Pincus LLC 250 6th Avenue SW
Calgary, AlbertaT2P 3H7
website: www.blackswanenergy.comInvestor Information Contact Phone: (403) 930‐4400
Christine Ezinga (403) 930‐4440VP Strategy & Planning [email protected]