CORPORATE PRESENTATION November 2019 SEVEN GENERATIONS ENERGY - - PowerPoint PPT Presentation
TSX: VII CORPORATE PRESENTATION November 2019 SEVEN GENERATIONS ENERGY Serving our stakeholders through: Differentiated attention to selection, development & replenishment of the lowest supply cost resource Best in class
TSX: VII
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(1) October 31, 2019 share price & shares outstanding as of September 30, 2019. (2) US$1.575B in senior unsecured notes converted at $1.3164 CAD/USD plus adjusted net working capital deficiency as of September 30, 2019 of $128 MM. (3) Figures may not add due to rounding. (4) For additional information see “Non-IFRS Measures Advisory” and “Other Definitions” in the “Important Notice” that appears at the end of the presentation.
Market Cap(1) $2.5 billion Share Count
Basic(1)
341 million Net Debt(2) $2.2 billion Adjusted Funds Flow
per Diluted Share(4)
$0.98 Enterprise Value(3) $4.7 billion Adjusted Funds Flow
($/boe)(4)
$18.09
(Trailing 12 Month)
4 1) For additional information, see “Forward Looking Information Advisory” and “Non-IFRS Measures Advisory” in the “Important Notice” at the end of this presentation
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1) For additional information, see “Forward Looking Information Advisory” and “Non-IFRS Measures Advisory” in the “Important Notice” at the end of this presentation.
$45+ WTI
Evaluate NCIB allocation Moderate corporate decline Free cash flow above US$50 WTI Land swap efficiencies Integrate Nest 3 development Define Nest 1 perimeter Full triple-stack Assess lower Montney areal extent
Montney development
perimeter areas
infrastructure
potential at $50+ WTI
across all 3 layers
boundaries
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1) Sustaining capital refers to capital expenditures including drilling, completions, equipping, tie-in and other expenditures required to maintain production from existing facilities at current levels. 2) Discretionary capital refers to capital expenditures that are not required to maintain production from existing facilities at current levels, including but not limited to delineation, infrastructure, value-enhancing projects, and production growth 3) For additional information, see “Forward-Looking Information Advisory” and “Other Definitions” in the “Important Notice” at the end of this presentation.
Growth Major Infra
Delineation Delineation Delineation Value Enhancing Value Enhancing Value Enhancing
7 1) E&P adjusted funds flow reflects US$2.50/MMbtu Henry Hub, US$5/bbl condensate differentials. 2) For additional information, see “Forward-Looking Information Advisory”, “Non-IFRS Measures Advisory” and “Other Definitions” in the “Important Notice” at the end of this presentation. 3) Sustaining capital refers to capital expenditures including drilling, completions, equipping, tie-in and other expenditures required to maintain production from existing facilities at current levels.
Strong balance sheet Large, high quality asset base Location/access to infrastructure Control/flexibility Skilled and knowledgeable staff
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Resource Quality & Low Supply Cost Market Access Free Cash Flow Stakeholder Service Return on Capital Financial Sustainability Return of Capital
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6.75% Notes US$425MM 6.875% Notes US$450MM 5.375% Notes US$700MM
3.5 Years to Next Maturity
1) For additional information, see “Forward-Looking Information Advisory” and “Non-IFRS Measures Advisory” in the “Important Notice” at the end of this presentation.
2023 is earliest senior unsecured note maturity
$1.3B available on $1.4B facility C$0.3B accordion 2023 maturity
Leverage is below 2x at US$50 WTI
10 (1) Non-IFRS financial measures. For additional information see “Non-IFRS Measures Advisory” and “Forward-Looking Information Advisory” in the “Important Notice” that appears at the end of the presentation. (2) Subsectors based on SPDR Select Indices: XLK, XLY, XLI, XLP, XLB, XLV, XLC, XLF, XLE, XLU, XLRE, and iShares XEG (TSX Capped Energy). (3) Montney firms include: AAV, ARX, BIR, CR, ECA, KEL, NVA, PIPE, PONY, POU, TOU.
2018 EBITDA / Total Average Capital (2) (3) (4)
17.4% 16.4% 17.9% 19.1% 2015 2016 2017 2018
(CROIC)(2)
30% 27% 27% 25% 25% 20% 19% 19% 18% 18% 16% 14% 12% 10%
Tech Cons. Disc. VII Industrials Staples Materials Healthcare Comms. Financials US Energy CDN Energy Montney Firms (4) Utilities Real Estate
Source: Bloomberg
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(1) 2020 full-year budgeted assumptions include US$50/bbl WTI, US$2.50/MMbtu Henry Hub, US$5/bbl condensate differentials. Adjusted funds flow and free cash flow shown above use the same assumptions with $60/bbl WTI price. (2) For additional information see “Forward-Looking Information Advisory” and “Non-IFRS Measures Advisory” in the “Important Notice” that appears at the end of the presentation.
As a Percentage of Adjusted Funds Flow
($MM)
12 1) Marty Proctor, Chief Executive Officer, is the only non-independent director. 2) Based upon 2017 data. For additional information regarding the company’s estimated carbon intensity, please refer to “Note Regarding Industry Metrics” in the “Important Notice” at the end of this presentation. Peers include ARX, BTE, CPG, HSE, SU, VET. 3) The peer companies in the Liability Management Rating chart include ARX, BIR, CNQ, CVE, CPG, ECA, ERF, HSE, MEG, PEY, TOU, VET, WCP.
commitment to sustainability
0.0 0.5 1.0 1.5 2014 2015 2016 2017 2018 2019 YTD
A Low GHGe Footprint vs Peers (2)
due to investments in disposal and water handling
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Peer 1 Peer 2 Peer 3 Peer 4 Peer 5 Peer 6 Peer 7 Peer 8 Peer 9 Peer 10 Peer 11 Peer 12 Peer 13 VII
0.00 0.05 0.10
VII Peer 1 Peer 2 Peer 3 Peer 4 Peer 5 Peer 6
Best in Class Environmental Liability Management (3)
royalty contributions in 2018, supporting economic activity in Western Canada
local stakeholders
volunteerism, from ~200 staff Total Recordable Incident Frequency
LMR Tonnes of CO2e / boe
Practices That Drive Diversity, Accountability and Effective Oversight
Annual Rate per 100 Full-Time Employees
13 1) All figures based on ISS QualityScore ratings, with 1 being the most favorable rating and 10 being the least favorable. 2018 figures are effective December 1, 2018. 2019 Figures are effective November 1, 2019. Figures are calculated relative to a selection of peers determined by ISS.
14 1) For additional information, see “Forward-Looking Information Advisory” and “Note Regarding Potential Drilling Opportunities” in the “Important Notice” at the end
Natural Gas Processing:
capacity access
Condensate Stabilization:
up to 20 Mbbl/d
Infrastructure Footprint
Canada’s largest producer
Nest IRRs average 125% at US$55 WTI / US$3 Hub
Nest upper/middle Montney: 15+ years Decades of lower Montney, Wapiti & Rich Gas future drilling opportunities
750 MMcf/d of owned gas processing capacity
15 1) 2018 average benchmark prices sourced from Bloomberg.
Revenue Mix
Condensate NGL Natural Gas
Chicago 49% Chicago 41% Chicago 38% Gulf 24% Gulf 26% Gulf 24% Malin 13% Malin 18% Dawn 15% Dawn 15% Dawn 14% AECO 10% AECO 5% AECO 5%
2019 2020 2021
7G Gas Market Sales Points
NGPL: 155 MMcf/d Alliance: 500 MMcf/d TCPL: 77 MMcf/d GTN: 90 MMcf/d $0.00 $1.00 $2.00 $3.00 Chicago Gulf Malin Dawn AECO
2019 YTD Benchmark Prices (US$/MMbtu)
16 1) Source: Bloomberg, COLC, NEB and 7G internal forecasts. 2) Source: Bloomberg. 3) For additional information, see “Forward-Looking Information Advisory” in the “Important Notice” at the end of this presentation.
Condensate Import Capacity = 275 Mbbl/d Implied Condensate Imports Required to Meet Demand (Mbbl/d)(3)
Edmonton Condensate vs. Crude Oil Prices (US$/bbl)(2) Forecast Supply & Demand of WCSB Condensate (Mbbl/d)(1)(3)
$10 $20 $30 $40 $50 $60 $70 $80
WTI Oil
Midland Oil WCS Heavy Oil
17 Partial triple-stack IP90: 1,048 boe/d 72% condensate Successful vertical test
1) For additional information, see “Forward-Looking Information Advisory” and “Note Regarding Potential Drilling Opportunities” in the “Important Notice” at the end of this presentation. 2) Assumes $11 MM in U/M DCET costs. $50 MM of super-pad and associated shared surface costs, $500k drilling savings on lower Montney, with 30% reduced well productivity.
Illustration not to scale
2,800-3,000 meters 200 metres 800 metres
Upper Montney Middle Montney Lower Montney Partial triple-stack IP30: 1,250 boe/d 63% condensate
Upper & Middle Montney Lower Montney Triple Stack Δ% Wells
(#)
24 12 36 +50% DCET
($MM)
$265 $126 $390 +47% Full Cycle Capex
($MM)
$315 $126 $440 +40% NPV
($MM)
$290 $85 $375 +30% Capital Efficiency
($/boe/d)
$12,200 $13,900 $12,500
Full triple-stack IP60: 1,520 boe/d 67% condensate (3-well average)
(prior to optimization)
Partial triple-stack IP30: 2,280 boe/d 31% condensate
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1) For additional information, see “Forward-Looking Information Advisory”, and “Note Regarding Development Area Forecast Economics and Type-Curves” in the “Important Notice” at the end of this presentation. 2) Capital efficiency represents total drilling, completion, equipping and tie-in costs divided by total average first-year daily production on a boe basis.
20 40 60 80 100 120 30 60 90 120 150 180 2018 Curve Latest Nest 3 Actuals
Cumulative condensate (Mbbl) vs. time (days)
IP94 1,730 boe/d 44% Condensate Flowtest IP20 (7 Hz) 1,068 – 1,972 boe/d ~63% Condensate IP60 (2 Hz) 1,413 – 1,963 boe/d ~64% Condensate IP96 2,030 boe/d 55% Condensate IP80 1,203 boe/d 52% Condensate IP90 1,464 boe/d 68% Condensate
Nest 1 2019 Activity
7G IP60 (Restricted Rates) ~1,898 boe/d 72% condensate
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1) The following pricing assumptions were used to develop the economic forecasts shown above: US$55.00 US/bbl WTI, US$3.00 US/mcf NYMEX/HH and 0.76 USD/CAD FX. NGLs as % of WTI: Alberta - C3 25%, C4 35%, C5 91%, Chicago - C3 35%, C4 45%, C5 95%. Chicago Basis US$0.15/mcf to NYMEX/HH and AECO Basis US$1.75/mcf to NYMEX/HH. Chicago transport US$1.20/mcf and AECO transport US$0.25/mcf. Variable liquids opex C$5.00/bbl and Variable gas opex C$0.60/mcf. Fixed well operating cost = $20,000/mo. 2) For additional information, see “Forward-Looking Information Advisory”, “Further Economic Assumptions”, “Note Regarding Development Area Forecast Economics and Type Curves” and “Note Regarding Potential Drilling Opportunities” in the “Important Notice” at the end of this presentation.
Key Stats Nest 1 (2014 Estimates) Nest 1 (2018 Estimates) IP30
(boe/d)
1,250 1,500 IP365
(boe/d)
675 775 DCET Cost
($MM)
$9.5 $11 IP365 CGR
(bbls/MMcf)
135 478 IRR
(%)
29% 83% NPV
($MM)
$2.3 $6.7
Competitor wells 50 100 150 200 250 300 90 180 270 360
2014 Curve Nest 1 Actuals
Cumulative condensate (Mbbl) vs. time (days)
Enhanced completions have improved well results
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Core Nest Development Inventory Nest 1 Nest 2 Nest 3 Weighted Average South East West North IP30
(boe/d)
1,500 1,950 - 2,350 2,000 1,900 IP365
(boe/d)
775 1,150 - 1,650 1,400 1,125 DCET Cost
($MM)
$11 $10.5 - $11.5 $11 $11 IP365 CGR
(bbls/MMcf)
478 90 160 170 295 55 280 IRR
(%)
83% 85% 150% >250% 215% 62% 125% NPV
($MM)
$6.7 $6.4 $11.5 $16.0 $12 $6.4 $8.9 PIR
(x)
0.6 0.6 1.0 1.5 1.1 0.6 0.8 Locations
(#)
480 90 170 75 280 190 1,285
1) For additional information, see “Forward-Looking Information Advisory” and “Note Regarding Potential Drilling Opportunities”, “Note Regarding Development Area Forecast Economics and Type-Curves” and “Further Economic Assumptions” in the “Important Notice” at the end of this presentation. Inventory counts and economics are based on year-end 2018 estimates. 2) PIRs reflect the NPVs divided by the DCET Costs (taken as the midpoint where ranges are provided).
Future Development Opportunities Nest Area Lower Montney Cretaceous Wapiti Rich Gas Total Undeveloped 2P Reserve Locations
(#)
7 68 75 Contingent (2C) Resource Locations
(#)
>170 >60 >250 >100 >730
High-impact upside Opportunistic development Longer-term delineation Potentially expand boundaries
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TSX: VII
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We believe that companies have only the rights given to them by society. While people have a natural entitlement to basic rights, corporations are an instrument created by society to provide its needs and ought to have no expectation of basic entitlements other than equitable rights with other corporations, including those wholly owned by a person. We recognize that rights, sufficient to build and
serve the legitimate needs of society in which they exist. To thrive, companies must differentiate, rise above the pack, standout as being among the best with all of their stakeholders. At Seven Generations Energy Ltd., we acknowledge this granted entitlement and accept from our stakeholders a duty to thrive and an understanding of the need to differentiate. Specifically, in acceptance of this challenge to differentiate with all stakeholders, we acknowledge:
The need of society for us to conduct our business in a way that protects the natural beauty of the environment and preserves the capacity of the earth to meet the needs
The need of our business partners and infrastructure customers to be treated fairly and attentively; The need of Canada and Alberta for us to obey all regulations and to proactively assist with the formulation
to better serve society; The need of our suppliers and service providers to be treated fairly and paid promptly for equipment and services provided to us and to receive feedback from us that can help them to be competitive and thrive in their businesses; The need of the communities where we operate to be engaged in the planning of our projects and to participate in the benefits arising from them as they are built and operated; The need of our employees to be compensated fairly and provided a safe, healthy and happy work environment including a healthy work life – outside life balance; and The need of our shareholders and capital providers to have their investment managed responsibly and ethically and to earn strong returns.
We see ourselves as being in the service business, serving the needs of our stakeholders. We seek satisfaction for all stakeholders. Differentiation is imperative. We support an open and competitive business environment, recognizing in the competitive world that we envision, only those who best serve their stakeholders can expect the support required to survive for the longer term.
Nest 2 Development Nest 1 & 3 Development Infrastructure Delineation Value Enhancing
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2019 Guidance Sustaining Capital(1) $1.1 billion Discretionary Capital(2) $0.15 billion Total Capital Investment $1.25 billion Average Production 200 - 205 Mboe/d H1/19 Production 195 - 200 Mboe/d H2/19 Production 205 - 210 Mboe/d Wells On Stream (#) 65 - 70 Percent Liquids 58 - 60% Royalty Rate at US$50 WTI 5 - 7% Royalty Rate at US$60 WTI 7 - 9% Operating Expenses ($/boe) $5.00 - $5.25 Transportation ($/boe) $6.75 - $7.25 G&A ($/boe) $0.80 - $0.90 Interest ($/boe) $1.80 - $1.90
1) Sustaining capital refers to capital expenditures including drilling, completions, equipping, tie-in and other expenditures required to maintain production from existing facilities at current levels. 2) Discretionary capital refers to capital expenditures that are not required to maintain production from existing facilities at current levels, including but not limited to delineation, infrastructure, value-enhancing projects, and production growth 3) For additional information, see “Forward-Looking Information Advisory” and “Other Definitions” in the “Important Notice” at the end of this presentation.
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C$62-$78 /bbl C$65-$77 /bbl
1) For additional information, see “Forward-Looking Information Advisory” in the “Important Notice” at the end of this presentation. 2) For full detailed hedge disclosure please refer to the next slide in this deck. Forecast hedged volume percentages are expressed as 2019 / 2020 / 2021 term hedged volumes expressed as a percent of after-royalty full-year 2019 volumes.
Crude Oil bbl/d bbl/d C$/bbl bbl/d bbl/d US$/bbl RoY 2019 16,000 $58.13 $74.90 2,000 $40.00 23,000 $58.64 $61.85 2,000 $40.00 2020 8,500 $57.06 $71.50 1,500 $40.00 19,750 $54.13 $59.11 3,750 $40.00 2021 $0.00 $0.00 $0.00 7,000 $53.85 $59.09 1,750 $40.00 2022 $0.00 $0.00 $0.00 1,250 $52.31 $52.31 $0.00 Natural Gas MMbtu/d MMbtu/d US$/MMbtu RoY 2019 90,000 $2.89 $3.02 10,000 $2.50 2020 102,500 $2.70 $2.84 $0.00 2021 42,500 $2.62 $2.96 $0.00 2022 5,000 $2.58 $3.05 $0.00 Natural Gas Basis Markets MMbtu/d US$/MMbtu MMbtu/d US$/MMbtu GJ/d RoY 2019 80,000 $2.83 10,000
60,000 $2.44 $2.85 2020 32,500 $2.74 55,000
10,000 $2.13 $2.13 2021 $0.00 52,500
$0.00 $0.00 2022 $0.00 12,500
$0.00 $0.00 . Foreign Exchange Notional (US$MM) RoY 2019 $56.0 1.2954 1.3027 2020 $292.6 1.2934 1.3039 2021 $179.6 1.2969 1.3114 2022 $30.4 1.3117 1.3298 Note: Swaps are treated as collars with puts and calls with same strike price. USD WTI Sold Puts US$/bbl AECO 7A Swaps & Collars C$/GJ Chicago Basis Swaps USD WTI Swaps and Collars Chicago CG Swaps C$/US$ C$/bbl CAD WTI Collars CAD WTI Sold Puts NYMEX HH Swaps & Collars US$/MMbtu NYMEX HH Sold Puts FX Swaps & Collars
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VII - Recent Quarterly Results OPERATING RESULTS Q3 2019 Q2 2019 Q1 2019 Q4 2018 Q3 2018 Q2 2018 Q1 2018 Q4 2017 Q3 2017 Q2 2017 Q1 2017 YE 2018 YE 2017 Average daily production Condensate (1) (mbbl/d) 75.5 75.9 72.7 81.8 87.3 69.0 67.3 70.0 64.5 59.0 51.6 76.4 61.3 Natural gas (MMcf/d) 515.3 489.6 483.6 515.4 511.3 461.3 473.3 493.4 453.2 409.6 384.5 490.5 435.5 NGLs (1) (mbbl/d) 43.2 44.3 44.1 47.4 47.3 41.2 41.5 45.1 43.9 37.9 37.4 44.4 41.1 Total (mboe/d) 204.6 201.8 197.4 215.1 219.8 187.1 187.7 197.3 183.9 165.2 153.1 202.6 175.0 CGR Ratio 147 155 150 155 175 150 142 142 142 144 134 156 141 LGR Ratio 84 90 91 92 93 89 88 91 97 93 97 91 94 Realized Prices Condensate (1) ($/bbl) 65.59 71.91 63.00 53.57 79.26 81.67 73.39 67.95 54.95 58.28 63.84 71.63 61.28 Natural gas ($/Mcf) 2.85 3.29 4.32 4.77 3.65 3.79 3.54 3.53 3.46 4.09 4.36 3.98 3.84 NGLs (1) ($/bbl) 2.74 4.19 7.46 8.44 14.02 13.39 13.33 18.30 15.18 11.45 12.45 12.21 14.56 31.97 35.95 35.44 33.66 42.99 42.42 38.19 37.13 31.43 33.58 35.52 39.33 34.45 FINANCIAL RESULTS (4) Condensate (1) ($MM) 455.6 496.7 412.2 403.2 636.6 512.8 444.5 437.6 326.1 312.9 296.5 1,997.3 1,371.1 Natural gas ($MM) 135.3 146.6 187.9 225.7 171.8 159.2 156.1 160.3 144.2 152.4 150.8 712.6 610.3 NGLs (1) ($MM) 10.9 16.9 29.6 36.8 61.0 50.2 49.8 76.0 61.3 39.5 42.1 197.8 218.3 Liquids and natural gas sales (2) ($MM) 601.8 660.2 629.7 665.7 869.4 722.2 650.4 673.9 531.6 504.8 489.4 2,907.7 2,199.7 Royalties ($MM) (37.5) (40.2) (40.9) (19.5) (44.4) (16.4) (18.9) (21.5) (14.5) (9.3) (16.8) (99.2) (62.1) Operating expense ($MM) (90.6) (91.8) (87.5) (103.8) (105.5) (102.2) (96.8) (103.3) (91.8) (93.9) (68.8) (408.3) (357.8) Transportation, processing and other expense ($MM) (121.6) (121.9) (118.1) (139.9) (124.2) (118.0) (109.7) (116.8) (109.4) (88.3) (74.3) (491.8) (388.8) Operating netback before the following (3) ($MM) 352.1 406.3 383.2 402.5 595.3 485.6 425.0 432.3 315.9 313.3 329.5 1,908.4 1,391.0 Realized hedging gain (loss) ($MM) 30.6 0.8 (6.0) (31.2) (36.2) (17.7) (13.1) 6.9 14.2 1.8 (7.2) (98.2) 15.7 Marketing Income (3)(5) ($MM) 3.6 1.3 13.6 3.9 5.7 9.1 10.0 11.8 4.6 6.3 2.3 28.7 25.0 Operating netback (3) ($MM) 386.3 408.4 390.8 375.2 564.8 477.0 421.9 451.0 334.7 321.4 324.6 1,838.9 1,431.7 Adjusted funds flow (3) ($MM) 340.6 355.0 338.5 337.4 522.0 434.0 380.8 403.8 284.3 268.1 272.1 1,674.2 1,228.3 Cash provided by operating activities ($MM) 320.4 422.1 259.3 410.1 536.9 425.2 424.1 310.3 314.1 193.9 336.0 1,796.3 1,154.3 Revenue (6) ($MM) 718.0 795.5 546.3 1,146.8 809.0 560.4 653.7 652.3 563.7 608.8 629.8 3,169.9 2,454.6 Net Income (loss) ($MM) 85.1 295.3 10.8 245.4 196.4 (24.6) 22.7 83.1 85.7 178.1 215.6 439.9 562.5 Netbacks (4) Liquids and natural gas sales ($/boe) 31.97 35.95 35.44 33.66 42.99 42.42 38.19 37.13 31.43 33.58 35.52 39.33 34.45 Royalties ($/boe) (1.99) (2.19) (2.30) (0.99) (2.20) (0.96) (1.12) (1.18) (0.86) (0.62) (1.22) (1.34) (0.97) Operating expense ($/boe) (4.81) (5.00) (4.93) (5.25) (5.22) (6.00) (5.73) (5.69) (5.43) (6.24) (4.99) (5.52) (5.60) Transportation, processing and other expense ($/boe) (6.46) (6.64) (6.65) (7.07) (6.14) (6.93) (6.24) (6.43) (6.47) (5.88) (5.39) (6.65) (6.09) Operating netback before the following (3) ($/boe) 18.71 22.12 21.56 20.35 29.43 28.53 25.10 23.83 18.67 20.84 23.92 25.82 21.79 Realized hedging gain (loss) ($/boe) 1.63 0.04 (0.34) (1.58) (1.79) (1.04) (0.78) 0.38 0.84 0.12 (0.52) (1.33) 0.25 Marketing Income (3)(5) ($/boe) 0.19 0.07 0.77 0.20 0.28 0.53 0.62 0.65 0.27 0.43 0.17 0.39 0.39 Operating netback (3) ($/boe) 20.53 22.23 21.99 18.97 27.92 28.02 24.94 24.86 19.78 21.39 23.57 24.88 22.43 General and administrative expense ($/boe) (0.84) (0.85) (0.94) (0.91) (0.66) (0.82) (0.65) (0.65) (0.65) (0.82) (0.79) (0.76) (0.72) Finance expense and other ($/boe) (1.60) (2.05) (2.00) (1.00) (1.45) (1.71) (1.75) (1.95) (2.33) (2.74) (3.03) (1.47) (2.48) Adjusted funds flow per boe (3) ($/boe) 18.09 19.33 19.05 17.06 25.81 25.49 22.54 22.25 16.80 17.83 19.75 22.65 19.23 Capital investments Drilling and completions ($MM) 171.0 172.9 231.4 148.9 232.6 335.9 319.6 167.4 252.8 342.3 259.4 1,037.0 1,021.9 Facilities and infrastructure ($MM) 76.9 119.5 132.2 67.7 90.8 179.3 207.0 115.0 176.5 153.9 85.2 544.8 530.6 Land and other ($MM) 36.7 18.7 37.3 45.7 34.8 47.4 56.0 39.9 25.0 16.3 17.7 183.9 98.9 Total capital investments ($MM) 284.6 311.1 400.9 262.3 358.2 562.6 582.6 322.3 454.3 512.5 362.3 1,765.7 1,651.4 (1) Starting in 2018, 7G began presenting C5+ in the NGL mix as a condensate volume (previously reported as an NGL volume). 2017 figures have been adjusted to conform to this current period presentation. (2) Excludes the purchase and resale of liquids and natural gas in respect of transportation commitment optimization and marketing activities. Refer to the Q3 2019 MD&A as filed on SEDAR for additional information. (3) For additional information, see "Non-IFRS Measures Advisory" in the "Important Notice" at the end of this presentation. (4) Certain prior period figures have been re-classified to conform with current period presentation. (5) The marketing income of the purchase and resale of liquids and natural gas, net of applicable pipeline tariffs, represent the margins earned in respect of the Company's transportation optimization and marketing activities. (6) Represents the total of liquids and natural gas sales, net of royalties, gains (losses) on risk management contracts and other income.
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1) Sources: Canadian Discovery Ltd. & Graham Davies Geological Consultants Ltd. (2008, 2011), & Steven Burnie (2011), BC Ministry of Energy & Mines, Alberta Geological Survey (modified by RBC & 7G) Lands as of 4/30/17.
Thickness→ Large Resources in Place Over Pressured→ High Productivity Brittle Rock→ High Recovery Factor Lower Temperature→ High Liquids Content
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General Advisory The information contained in this presentation does not purport to be all- inclusive or contain all information that readers may require. Prospective investors are encouraged to conduct their own analysis and review of Seven Generations Energy Ltd. (“Seven Generations”, “7G”, “VII”, the “company” or the “Company”) and of the information contained in this presentation. Without limitation, prospective investors should read the record of publicly filed documents relating to the Company, consider the advice of their financial, legal, accounting, tax and other professional advisors and such other factors they consider appropriate in investigating and analyzing the Company. An investor should rely only on the information provided by the Company and is not entitled to rely on parts of that information to the exclusion of others. The Company has not authorized anyone to provide investors with additional
different information, and any such information, including statements in the media about Seven Generations, should not be relied upon. In this presentation, unless
per share amounts are presented on a diluted basis. An investment in the securities of Seven Generations is speculative and involves a high degree of risk that should be considered by potential investors. Seven Generations’ business is subject to the risks normally encountered in the
natural gas sector of the oil and natural gas industry, and certain other risks that are associated with Seven Generations’ stage of development. An investment in the Company’s securities is suitable only for those purchasers who are willing to risk a loss of some or all of their investment and who can afford to lose some or all of their investment. Non-IFRS Measures Advisory In addition to using financial measures prescribed by International Financial Reporting Standards (“IFRS”), references are made in this presentation to “available funding”, “adjusted funds flow per diluted share”, “adjusted funds flow per boe”, “operating netback” (also referred to herein as “netback”), “adjusted EBITDA”, “return on capital employed” (or “ROCE”), “EBITDA”, “adjusted working capital”, “marketing income”, “cash return on invested capital” (or “CROIC”), “capital efficiency” and “free cash flow”, which are measures that do not have any standardized meaning as prescribed by IFRS. Accordingly, the Company’s use of such terms may not be comparable to similarly defined measures presented by other entities and comparisons should not be made between such measures provided by the Company and by other companies without also taking into account any differences in the way that the calculations were prepared. For further details about “available funding”, “adjusted funds flow per boe”, “operating netback”, “adjusted EBITDA”, “return on capital employed” (or “ROCE”), “adjusted working capital”, “marketing income”, “cash return on invested capital” (or “CROIC”) and reconciliations between these measures and the most directly comparable measures under IFRS, see “Non- IFRS Financial Measures” in the Company’s Management’s Discussion and Analysis dated November 6, 2019, for the three and nine months ended September 30, 2019 and 2018, which is available on the SEDAR website at www.sedar.com. The 2018 EBITDA figure ($1,815 million) that is referenced for 7G on the slide titled “7G’s Track Record of Industry Leading Returns” was derived from 2018 Net income ($440 million), after adding back the effects of interest ($127 million), taxes ($233 million), DD&A ($847 million), FX Gain/Loss ($166 million) and loss on associate ($2 million). Adjusted funds flow per diluted share and adjusted funds flow per boe were calculated by dividing adjusted funds flow by the Company’s diluted share count and total barrel of oil equivalent sales volumes, respectively. Capital efficiency represents total drilling, completion, equipping and tie-in costs divided by total average first-year daily production on a boe basis. For additional information about “adjusted funds flow” and “net debt”, which are measures that have been prepared in accordance with IFRS, please see note 17 of the company’s Consolidated Financial Statements for the years ended December 31, 2018 and 2017 and note 14 of the company’s condensed interim consolidated financial statements for the three and nine months ended September 30, 2019 and 2018, available on the SEDAR website. Forward-Looking Information Advisory This presentation contains certain forward-looking information and statements that involve various risks, uncertainties and other factors. The use of any of the words “anticipate”, “continue”, “estimate”, “expect”, “may”, “will”, “should”, “believe”, “plans”, “outlook”, “forecast” and similar expressions are intended to identify forward-looking information or statements. In particular, but without limiting the foregoing, this presentation contains forward-looking information and statements pertaining to the following: the Company’s strategies, strategic pursuits, priorities, goals, strategic objectives and competitive strengths; development plans and timing of development; the selection, development and replenishment of the lowest supply cost resource; best in class execution through safe, responsible, innovative and efficient development; maximization
an unwavering focus on balance sheet strength; free cash flow potential and ability to sustain a free cash flow generating business model; expected drilling inventory/ potential drilling
potential inventory expansion; expected number of years to develop drilling inventory/potential drilling
the expected moderation of corporate production decline rates; planned capital investments and capital allocation including references to sustaining capital and discretionary capital; the information on the slides titled “2020 Capital Budget & Guidance” and “2019 Budget”, including expected production, development wells to be brought on stream, liquids yields, royalty rates,
capital investments will be organically funded at stated commodity price assumptions; plans for commodity price upside to be returned to shareholders in the form of share buybacks and/or net debt reduction; expectation that certain value enhancements will improve average future condensate pricing; future net debt to adjusted EBITDA forecasts; forecast supply and demand of condensate; imports of condensate expected to be required to meet demand; potential benefits from further development of the lower Montney formation and further development in the Nest 3 area; projections regarding adjusted funds flow and funds flow sensitivities; access to sales points; delineation potential and planned delineation; possible expansion of the boundaries of the Nest area with further delineation; forecast economics, including single well economics, IRRs, break-even costs, NPVs and PIRs; hedge targets; objectives of hedging program; the information provided under “Illustrative Economic Uplift Potential” and “Potential Benefits” on the slide titled “Lower Montney – Emerging Development Potential”; the information provided on the slide titled “Near Term Development Goals”; strong netbacks expected to be maintained; improved execution, optimization and cost control expected in the future; plans to use leverage conservatively and maintain ample liquidity; upside potential; future capital efficiency; future prices and the references to development area forecasts and type-curve estimates. In addition, information and statements in this presentation relating to reserves and resources are deemed to be forward- looking statements as they involve the implied assessment, based on certain estimates and assumptions, that the reserves and resources described exist in the quantities predicted or estimated, and that the they can be profitably produced in the future With respect to forward-looking information contained in this presentation, assumptions have been made regarding, among other things: future oil, NGLs and natural gas prices being consistent with current commodity price forecasts after factoring in quality adjustments at the company’s points of sale; the company’s continued ability to obtain qualified staff and equipment in a timely and cost-efficient manner; third party transportation and processing facilities will be operated in an efficient and reliable manner; drilling and completions techniques and infrastructure and facility design concepts that have been successfully applied by the Company elsewhere in its Kakwa River Project may be successfully applied to other properties; that wells drilled in the same fashion in the same formations in proximity to the type-wells that were used in 7G’s type-curve forecasts will deliver similar production results, including liquids yields; geology and reservoir quality being relatively consistent within each of the Company’s separate asset areas; well results from future wells to be drilled in the Company’s asset areas being similar to wells that have been drilled in those areas to date, as well as the type-curve estimates for those areas; the consistency of the current regulatory regime and legal framework, including the laws and regulations governing the company’s oil and gas
which the Company conducts its business and any other jurisdictions in which the Company may conduct its business in the future; the company’s ability to market production of oil, NGLs and natural gas successfully to customers; that the company’s future production levels, amount of future investment, costs, royalties, unabsorbed demand charges, facilities downtime and development timing will be consistent with the company’s current development plans and budget; the pace of development will be consistent with the company’s current plans; the applicability of new technologies for recovery and production of the company’s reserves and resources may improve capital and operational efficiencies in the future; the recoverability of the company’s reserves and resources; sustained future capital investment by the company; future cash flows from production; the Company’s future sources
funding; the Company’s future debt levels; geological and engineering estimates in respect
the Company is conducting exploration and development activities, and the access, economic, regulatory and physical limitations to which the Company may be subject from time to time; the impact of competition on the Company; and the Company’s ability to obtain financing on acceptable terms. Except where otherwise indicated, the adjusted funds flow, free cash flow and adjusted EBITDA forecasts referenced in this presentation were calculated based upon the assumptions outlined on the slide titled “2020 Capital Budget & Guidance” and the following commodity pricing assumptions: US$50.00/bbl WTI, US$2.50/MMbtu NYMEX/HH and 0.75 USD/CAD FX. NGLs as % of WTI: C3 26%, C4 30%, C5 – $5 USD/bbl differential. AECO Basis US$1.15/MMbtu. Operating cost assumptions reflect recent actual cost trends with adjustments to address planned activity levels. Royalty rate assumptions were calculated using a price range of US$50-US$60/bbl WTI, net of credits as of December 31, 2019 and projected C* for new wells to be drilled in 2020. Royalty rate assumptions are net of expected gas cost allowance investments in gas plants. G&A cost assumptions reflect recent actuals and expectations for a staff count and information technology investments in 2020.
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Net debt forecasts were calculated by adding the principal of the unsecured notes to the forecasted principal of the Company’s credit facility, less forecast adjusted net working capital. Assumptions made in the calculations of forecasted economics, including forecasted NPVs, IRRs, price sensitivities, commodity prices and recovery factors reflect cost assumptions that are based upon recent actual cost trends with adjustments to address planned activity levels. Royalty rates were calculated using a price range of US$50-US$65/bbl, net of credits as
Royalty rates were calculated net
expected gas cost allowance investments in gas plants. G&A costs used in the forecasts reflect recent actuals and expectations for a larger staff count and IT investments in 2019. An assumption has also been made that further well delineation activities will confirm management’s estimates regarding reservoir quality of its properties that fall outside of the Company’s core development areas. With respect to the estimated number of drilling locations or potential drilling
made. These assumptions are described under the heading “Note Regarding Potential Drilling Opportunities” below. Actual results could differ materially from those anticipated in the forward- looking information that is contained herein as a result of the risks and risk factors that are set forth in the company’s annual information form dated February 27, 2019 for the year ended December 31, 2018 (“AIF”), which is available on the SEDAR website, including, but not limited to: volatility in market prices and demand for oil, NGLs and natural gas and hedging activities related thereto; general economic, business and industry conditions; variance of the company’s actual capital costs, operating costs and economic returns from those anticipated; the ability to find, develop or acquire additional reserves and the availability of the capital or financing necessary to do so on satisfactory terms; risks related to the exploration, development and production of oil and natural gas reserves and resources; negative public perception of oil sands development, oil and natural gas development and transportation, hydraulic fracturing and fossil fuels; actions by governmental authorities, including changes in government regulation, royalties and taxation; political risk; potential legislative and regulatory changes; the rescission, or amendment to the conditions, of groundwater licenses of the company; management of the company’s growth; the ability to successfully identify and make attractive acquisitions, joint ventures or investments, or successfully integrate future acquisitions or businesses; the availability, cost or shortage of rigs, equipment, raw materials, supplies or qualified personnel; the adoption
modification
climate change legislation by governments and the potential impact of climate change on the company's
absence
loss
uncertainty associated with estimates of oil, NGLs and natural gas reserves and resources and the variance of such estimates from actual future production; dependence upon compressors, gathering lines, pipelines and
satisfy obligations under the company’s firm commitment transportation arrangements; the uncertainties related to the company’s identified drilling locations; the high-risk nature of successfully stimulating well productivity and drilling for and producing oil, NGLs and natural gas; operating hazards and uninsured risks; the risks of fires, floods and natural disasters, which could become more frequent or of a greater magnitude as a result of climate change; the possibility that the company’s drilling activities may encounter sour gas; execution risks associated with the company’s business plan; failure to acquire or develop replacement reserves; the concentration of the company’s assets in the Kakwa River Project; unforeseen title defects; indigenous claims; failure to accurately estimate abandonment and reclamation costs; development and exploratory drilling efforts and well
drilling and completion technique risks and failure of drilling results to meet expectations for reserves
production; limited intellectual property protection for operating practices and dependence on employees and contractors; third-party claims regarding the company’s right to use technology and equipment; expiry of certain leases for the undeveloped leasehold acreage in the near future; failure to realize the anticipated benefits of acquisitions or dispositions; failure of properties acquired now or in the future to produce as projected and inability to determine reserve and resource potential, identify liabilities associated with acquired properties or
protection from sellers against such liabilities; government regulations; changes in the application, interpretation and enforcement of applicable laws and regulations; environmental, health and safety requirements; restrictions on development intended to protect certain species of wildlife; potential conflicts of interests; actual results differing materially from management estimates and assumptions; seasonality of the company’s activities and the oil and gas industry; alternatives to and changing demand for petroleum products; extensive competition in the company’s industry; changes in the company’s credit ratings; third party credit risk; dependence upon a limited number of customers; lower oil, NGLs and natural gas prices and higher costs; failure of seismic data used by the company to accurately identify the presence of oil and natural gas; risks relating to commodity price hedging instruments; terrorist attacks or armed conflict; cyber security risks, loss of information and computer systems; inability to dispose of non-strategic assets on attractive terms; the potential for security deposits to be required under provincial liability management programs; reassessment by taxing or regulatory authorities of the company’s prior transactions and filings; variations in foreign exchange rates and interest rates; risks associated with counterparties in risk management activities related to commodity prices and foreign exchange rates; sufficiency of insurance policies; potential for litigation; variation in future calculations of non-IFRS measures; breach of agreements by counterparties and potential enforceability issues in contracts; impact of expansion into new activities on risk exposure; inability of the company to respond quickly to competitive pressures; and the risks related to the common shares that are publicly traded and the company’s senior notes and other indebtedness. Financial outlook and future-oriented financial information contained in this presentation regarding prospective financial performance, financial position, cash flows or well economics are based on assumptions about future events, including economic conditions and proposed courses of action, based on management’s assessment of the relevant information that is currently available. Projected operational information also contains forward- looking information and is based on a number of material assumptions and factors, as are set out herein. Such projections may also be considered to contain future oriented financial information or a financial outlook. The actual results of the Company’s operations for any period will likely vary from the amounts set forth in these projections, and such variations may be
and future-oriented financial information has been included in this presentation to inform readers of the estimated implications of the capital investments planned by the company. Readers are cautioned that any such financial outlook and future-oriented financial information contained herein should not be used for purposes other than those for which it is disclosed herein. The forward-looking statements included in this presentation are expressly qualified by the foregoing cautionary statements and are made as of the date of this presentation. The Company does not undertake any obligation to publicly update or revise any forward-looking statements except as required by applicable securities laws. No assurance can be given that these expectations will prove to be correct and such forward-looking statements included in this presentation should not be unduly relied upon. Certain information contained herein has been prepared by third-party sources (and is identified as such) and has not been independently audited
Presentation of Oil and Gas Information Estimates
the Company’s reserves, contingent resources and prospective resources contained herein are based upon the reports dated February 27, 2019 prepared by McDaniel & Associates Consultants Ltd. (“McDaniel”), the Company’s independent qualified reserves evaluator, as at December 31, 2018 (the “McDaniel Reports”). The estimates of reserves, contingent resources and prospective resources provided in this presentation are estimates only and there is no guarantee that the estimated reserves, contingent resources and prospective resources will be recovered. Actual reserves, contingent resources and prospective resources may be greater than or less than the estimates provided in this in this presentation and the differences may be material. There is no assurance that the forecast price and cost assumptions applied by McDaniel in evaluating Seven Generations’ reserves, contingent resources and prospective resources will be attained and variances could be material. There is no certainty that any portion of the prospective resources will be
viable to produce any portion of the prospective resources. There is also uncertainty that it will be commercially viable to produce any part of the contingent resources. This presentation includes estimates
contingent resources and prospective resources, as at December 31, 2018, that have been risked by McDaniel for the probability of loss or failure in accordance with the COGE
likelihood that an accumulation will be commercially developed is referred to as the chance of development. Contingent resources in the “development pending” project maturity subclass have been assigned by McDaniel, as at December 31, 2018, in the upper, middle and lower intervals of the Montney formation in certain parts of the Nest 1, Nest 2, Nest 3, Rich Gas and Wapiti areas within the Kakwa River Project. The COGE Handbook indicates that it is appropriate to categorize contingent resources in the development pending project maturity subclass where resolution of the final conditions for development are being actively pursued and there is a high chance of
the Company’s properties by McDaniel, as at December 31, 2018, have been classified as “development pending” and the balance of the contingent resources have been classified as “development unclarified”. Contingent resources in the “development unclarified” project maturity subclass have been assigned by McDaniel, as at December 31, 2018, in the Wilrich formation within the Cretaceous stack across the Project area. The COGE Handbook indicates that it is appropriate to categorize contingent resources in the “development unclarified” project maturity subclass when the evaluation is incomplete and there is ongoing activity to resolve any risks or
produce any portion of the contingent resources.
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Prospective resources have both an associated chance of discovery and a chance
development. Not all exploration projects will result in
discovery of petroleum is referred to as the chance of discovery. For an undiscovered accumulation, the chance of commerciality is the product of two risk components - the chance of discovery and the chance of
River Project have been sub-classified as “prospect” by McDaniel, which the COGE Handbook defines as a potential accumulation within a play that is sufficiently well defined to present a viable drilling target. Approximately 40% of the prospective resources would be expected to be upper and middle Montney wells in the Wapiti and Rich Gas areas, and approximately 58% would be expected to be lower Montney wells across the Project area and approximately 2% would be expected to be within the Wilrich formation within the Cretaceous stack across the Project area. The evaluation of the risks and the risking process relevant to the contingent resources and prospective resources estimates that are contained herein are described in the AIF, which is available on the SEDAR website. The reserves and resources estimates contained in this presentation should be reviewed in connection with the AIF, which contains important additional information regarding the independent reserve, contingent resource and prospective resource evaluations that were conducted by McDaniel and a description of, and important information about, the reserves and resources terms used in this presentation. Note Regarding Industry Metrics This presentation includes certain industry metrics, including barrels of oil equivalent (“boes”) and GHGe or CO2e, which do not have standardized meanings or standard methods of calculation and therefore such measures may not be comparable to similar measures used by other companies and should not be used to make comparisons. Such metrics have been included herein to provide readers with additional information to evaluate the Company’s performance; however, such measures are not reliable indicators
the future performance
the Company and future performance may not compare to the performance in previous periods. Unless otherwise specified, all production is reported on the basis of the company’s working interest (operating and non-operating) before the deduction of royalties payable. Seven Generations has adopted the standard of 6 Mcf:1 bbl when converting natural gas to boes. Condensate and other NGLs are converted to boes at a ratio of 1 bbl:1 bbl. Boes may be misleading, particularly if used in isolation. A boe conversion ratio of 6 Mcf: 1 bbl is based roughly on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the Company’s sales point. Given the value ratio based on the current price of oil as compared to natural gas and NGLs is significantly different from the energy equivalency of 6 Mcf: 1 bbl and 1 bbl: 1 bbl, respectively, utilizing a conversion ratio at 6 Mcf: 1 bbl for natural gas and 1 bbl: 1 bbl for NGLs, may be misleading as an indication of value. The GHGe or CO2e estimates for 7G that are provided herein were calculated by the company. For the 2018 reporting year, based on 2017 performance, 7G’s carbon intensity of 0.0136 tonnes of CO2e per boe, the lowest carbon intensity estimate compared to six peer companies, was calculated by 7G. 7G quantified and reported its GHG emissions using what is referred to as the “operational control” approach. 7G’s deemed
extraction and processing facilities (including well pads). 7G elected to report its Scope 1 and 2 GHG emissions and not to report its Scope 3 GHG
emissions were defined as direct emissions from GHG sources that 7G
equipment, mobile combustion, and process emissions and fugitive emissions); (ii) Scope 2 emissions were defined as indirect GHG emissions that resulted from 7G’s consumption of energy in the form of purchased electricity; and (iii) Scope 3 emissions were defined as 7G’s indirect emissions other than those covered in Scope 2, including from all sources not owned or controlled by 7G, but which occurred as a result of 7G’s activities. Notably, 7G’s drilling and completion activities in the relevant periods were conducted by third parties and, consequently, those activities were deemed to be Scope 3. 7G retained Brightspot Climate Inc. to support the quantification of its 2018 GHG emissions. Emissions for all facilities were quantified in accordance with the methodologies specified in Alberta’s Carbon Competitiveness Incentive Regulation (“CCIR”) and Specified Gas Reporting Regulation (“SGRR”), and Environment and Climate Change Canada’s Greenhouse Gas Emissions Reporting Program, as applicable. Measured quantities, such as fuel volume, fuel carbon content, flare volumes, venting volumes, fugitive volumes, and electricity consumption were used, where metered data was available. Emission factors from published government sources were applied to the calculations. Third party verification was conducted by Millennium EMS Solutions. This verification was completed in accordance with the ISO 14064:3 standard and the requirements of CCIR. Note Regarding Development Area Forecast Economics and Type- Curves Type-curves were used to develop the development area forecast economics shown in this presentation. The type-curves were prepared by internal qualified reserves evaluators from 7G. For each of the type-curves, wells with significant deviation in completions technique, or that had mechanical issues
parent-child interactions between wells, were excluded from the analysis to avoid perceived outlier effects. Non- producing days were removed from the producing time plotted in the type-
constraints, parent-child well interactions, mechanical issues, expected downtime for concurrent operations, facility outages and gas processing shrink adjustment factors are then accounted for, but those assumptions and adjustments are not reflected in the type-curves themselves or in the forecast economics that have been provided in this presentation. All data reflected in the type-curves is raw wellhead data. Condensate rates have been adjusted downwards in the type-curves to account for assumed shrinkage due to entrainment of NGLs in the wellhead separator liquid, as directly measured. This correction is the result of an empirical equation based upon internal observations of sample data. Raw gas has not been adjusted and includes significant NGLs in the gas stream. The referenced type-curves were prepared using a combination of statistical approaches to early-life production from the type-wells selected, matched to volumetric estimates attributable to properties in the Company’s Nest 1, Nest 2 (North, South, East, West) and Nest 3 areas, respectively, based upon the Company’s understanding of the geology and reservoir parameters at the time the type curves were developed. Early-life statistics use data from the Nest 1, Nest 2 (East) and Nest 3 type-wells, adjusted for stage count and lateral length on a producing rate versus time basis, a cumulative volume versus time basis, and a producing rate versus cumulative volume basis, to ensure a reasonable fit. For Nest 2 (North, South, West) recent high intensity completion wells were selected that are adjacent to undeveloped acreage, with no adjustment made for stage count
The Nest 1 type-curve that was referenced is the same type-curve that was provided in the prospectus filed in connection with the Company’s IPO. That type-curve is based upon production data from wells that were drilled in 2014 and prior years and reflects a 2,200 m lateral well length and a 28 stage, 120 tonnes of proppant per stage completion design, utilizing N2 foam as the fracturing fluid. 11 wells drilled in the upper and middle Montney formation provide the statistical basis for the Nest 1 type-curve. The various Nest 2 type-curves referenced were created in July 2018 based upon production data from the wells that are described below: These Nest 2 wells were used because they are considered to be reflective
interactions, unusually tight spacing, facility constraints, downtime and mechanical failures. Historical tonnage and stage counts may not be representative of go-forward completion designs. The Nest 2 (South) type curve is based on production data from wells drilled in 2016-2017 that were landed at various depths in the top 125 m (average 67m) from the top of the Montney formation and utilized slickwater completions. The Nest 2 (North) type curve is based on production data mostly from wells drilled in 2016-2017 with varying horizontal landing depths from 35m to 110m (average 79 m) from the top of the Montney formation and were completed with slickwater completions. The Nest 2 (West) type curve is based on production data from wells completed in 2017 that were landed from 20m to 95m from the top of the Montney formation and were completed with slickwater completions. Type-wells in the Nest 2 (East) area were drilled in 2014 and 2015 using N2 foam as the fracturing fluid and were initially facility constrained. To develop the type-curve for the region, production rates from the unconstrained period of flow were extrapolated to create an estimated early flow profile, while taking into account cumulative production volumes, and then the results were compared to type-wells in the surrounding areas to ensure for consistency. The Nest 3 type-curve was created in the fourth quarter of 2017. It is based upon production data from wells that were drilled in 2017 and prior years and reflects a 2,500 m lateral well length and a 40 stage, 200 tonnes of proppant per stage completion design, utilizing slickwater as the fracturing
statistical basis for the Nest 3 type-curve.
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The Company has opted to rely upon the type-curve forecasts that have been prepared by internal qualified reserves evaluators from 7G in this presentation, rather than the type-curves prepared by McDaniel, because the internally generated type-curves are what the Company has used for capital budgeting and corporate planning purposes. Type-curves do not have any standardized preparation methodology or meaning and readers are cautioned that the type-curves and forecast development area economics shown in this presentation may not be comparable to similar information that is presented by other companies. Actual results may vary significantly from the Company’s forecasts and estimates. The Company’s oil, natural gas and NGL reserves, contingent resources and prospective resources, as at December 31, 2018, were evaluated by McDaniel in the McDaniel Reports. In the McDaniel Reports, McDaniel assigned proved plus probable reserves to approximately 72% of the Nest 1 sections evaluated; best estimate contingent resources to approximately 28% of the Nest 1 sections evaluated; proved plus probable reserves to approximately 90% of the Nest 2 sections evaluated; best estimate contingent resources to approximately 10% of the Nest 2 sections evaluated; proved plus probable reserves to approximately 55% of the Nest 3 sections evaluated; best estimate contingent resources to approximately 45% of the Nest 3 sections evaluated; proved plus probable reserves to approximately 19% of the Wapiti sections evaluated; best estimate contingent resources to approximately 60%
the Wapiti sections evaluated and best estimate prospective resources to approximately 21%
On the slide titled “Summary of Premium Single Well Economics & Other Inventory”, the following pricing assumptions were used to develop the economic forecasts shown: US$55.00/bbl WTI, US$3.00/mcf NYMEX/HH and 0.76 USD/CAD FX. NGLs as % of WTI: Alberta - C3 25%, C4 35%, C5 91%, Chicago - C3 35%, C4 45%, C5 95%. Chicago Basis US$0.15/mcf to NYMEX/HH and AECO Basis US$1.75/mcf to NYMEX/HH. Chicago transport US$1.20/mcf and AECO transport US$0.25/mcf. Variable liquids
cost = $20,000/mo. NGL recoveries and shrinkage factors reflected in the analysis are based on the company’s best estimate of the liquids to be extracted at the Pembina Kakwa River Plant and at 7G’s wholly owned plants in Alberta, as well as the liquids to be processed by Aux Sable at its facilities near Chicago, Illinois pursuant to the terms of the rich gas premium agreement between 7G and Aux Sable, which depends upon an assumed heating value and has been assumed to extend for the entire productive life of the wells. The forecast economics reflected are half-cycle economics and include
take into account certain other costs that would be required to construct infrastructure, including Super Pads, central processing facilities, regional gathering facilities, condensate stabilization facilities and
infrastructure, nor do they take into account land acquisition costs, corporate overhead (G&A) expenses, financing costs or corporate taxes. Such forecast economics are intended to represent the marginal return of a single well investment on an existing Super Pad. No adjustments were made for expected downtime or facility constraints, so the forecasts present an idealistic view of results that could be achieved in the absence of additional infrastructure costs, operational challenges or downtime. Actual results will differ from the forecasts for the reasons described above and because of the risks and risk factors that are described in the “Forward- Looking Information Advisory” set forth above. NPV figures have been calculated using a 10% annual discount factor. Note Regarding Potential Drilling Opportunities The references to drilling locations or potential drilling opportunities that are contained herein were prepared by internal qualified reserves evaluators from Seven Generations, as at December 31, 2018. Some of the locations have already been drilled as part of the Company’s 2019 development program. Of the 480 potential drilling locations or drilling opportunities that were estimated to be contained within the company’s Nest 1 area, as at December 31, 2018, 64% were attributed proved plus probable reserves and 36% were attributed best estimate contingent resources in the McDaniel Reports. Of the 615 potential drilling locations or drilling opportunities that were estimated to be contained within in the company’s Nest 2 area, as at December 31, 2018, 78% were attributed proved plus probable reserves and 22% were attributed best estimate contingent resources in the McDaniel Reports. Of the 190 potential drilling locations or drilling opportunities that were estimated to be contained within in the company’s Nest 3 area, as at December 31, 2018, 68% were attributed proved plus probable reserves, and 32% were attributed best estimate contingent resources in the McDaniel Reports. For the purposes of estimating potential drilling locations or drilling
section and a lateral well lengths of 2,310 metres based upon industry practice and internal review. The anticipated well spacing and lateral well length is expected to change over time as technology and the Company’s understanding of the reservoir changes. For the purposes of the estimates, the Company has assumed that natural gas production will be delivered into the Alliance Pipeline or NGTL system and that liquids will be extracted at the Pembina Kakwa River plant, at 7G’s wholly-owned plants in Alberta and at Aux Sable’s facilities near Chicago, Illinois. The number of future drilling opportunities described for the “Nest Area Lower Montney”, “Cretaceous”, “Wapiti” and “Rich Gas” areas on the slide titled “Summary of Premium Single Well Economics & Other Inventory” represents the number of locations estimated to be attributed to those areas by McDaniel in the McDaniel reports. For additional information refer to the AIF, which is available on the SEDAR website. There is no certainty that the company will drill any of the identified drilling
locations will result in additional reserves, resources or production. The drilling locations on which the company will actually drill wells, including the number and timing thereof, will be dependent upon the availability of funding, regulatory approvals, seasonal restrictions, oil and natural gas prices, costs, actual drilling results, additional reservoir information that is
drilling locations have been de-risked by drilling existing wells in relative close proximity to such locations, many of the locations are further away from existing wells, where management has less information about the characteristics of the reservoir and therefore there is more uncertainty as to whether wells will be drilled in such locations, and if wells are drilled in such locations there is more uncertainty that such wells will result in additional oil and natural gas reserves, resources or production. The competitor flow test and initial production history shown on the slide titled “Nest 1 Development – Ultra-Rich Condensate Region” has been
information was provided to such public sources by 7G’s competitors and 7G is unable to confirm if the information is accurate or was provided in accordance with applicable regulatory requirements. All of the competitor wells referenced were drilled in the Montney formation. The information is considered to be relevant because the geology of properties owned by 7G are considered to be similar to the competitor properties that are
for the flowtests and early production history, and pressure transient analysis and well test interpretation had not yet been carried out at the time the data was posted. As such, the information should be considered to be preliminary until further analysis and interpretation has been completed. The Nest 1 well that is described on that same slide was drilled in the middle interval of the Montney formation in the company’s Nest 1 area. The results have been obtained during a 60 day initial flow period (includes completions flowback and flow through permanent facilities). The average gas production rate observed to date is 3,136 Mcf/d and the average condensate production rate observed to date is 1,375 bbl/d. Cumulative gas production has been 188 MMcf, cumulative condensate production has been 82,505 bbls and cumulative produced water has been 59,082 bbls. Gas, condensate, and water rates ramped up over a period of 12 days. Gas maintained a plateau rate of about 4,100 Mcf/d) while condensate gradually declined as expected. Tubing pressure reached a maximum of 9,300 KPa (1,350 psi) after 5 days of flow and gradually decreased to about 3,500 KPa (510 psi), consistent with a relatively high liquid/gas ratio of about 750 bbl/MMcf. Pressure transient analysis and well test interpretation has not yet been conducted for this well. The “successful vertical test” referenced on the slide titled “Lower Montney Emerging Development Potential” reflects a production test conducted by the Company in the lower Montney formation. The full duration of the test was 5 days with 4.2 days of flowing hydrocarbons (water was produced for the first 1.2 days). During the test a total of 11,436 bbls of load fluid was also recovered. Significant production and pressure decline was noted during the test and pressure transient analysis and well test interpretation has not been carried out. Such data should be considered to be preliminary until further analysis and interpretation has been completed. The lower Montney wells drilled on “triple-stack” pads shown on the slide titled “Lower Montney – Emerging Development Potential” were drilled in the Nest 2 area. The initial and/or early production rates described in this presentation are not necessarily indicative of longer-term performance or ultimate recovery.
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Oil and Gas Definitions “best estimate” is a classification of estimated resources described in the “COGE Handbook” or “COGEH”, which is considered to be the best estimate of the quantity that will actually be recovered. It is equally likely that the actual quantities recovered will be greater or less than the best
the actual quantities recovered will equal or exceed the estimate. “COGE Handbook” means the Canadian Oil and Gas Evaluation Handbook maintained by the Society of Petroleum Evaluation Engineers (Calgary Chapter), as amended from time to time. “contingent resources” are those quantities of petroleum estimated, as of a given date, to be potentially recoverable from known accumulations using established technology or technology under development, but which are not currently considered to be commercially recoverable due to one or more
environmental, social, political factors and regulatory matters, a lack of markets or a prolonged timetable for development. It is also appropriate to classify as contingent resources the estimated discovered recoverable quantities associated with a project in the early evaluation stage. “gross” means: (i) in relation to the Company’s interest in production, reserves, contingent resources or prospective resources, its “company gross” production, reserves, contingent resources
prospective resources, which are the Company’s working interest (operating or non-
royalty interests of the Company; (ii) in relation to wells, the total number of wells in which a company has an interest; and (iii) in relation to properties, the total area of properties in which the Company has an interest. “liquids” refers to oil, condensate and other NGLs. “net” means: (i) in relation to the Company’s interest in production or reserves, the Company’s working interest (operating or non-operating) share after deduction of royalty obligations, plus the Company’s royalty interest in production or reserves; (ii) in relation to the Company’s interest in wells, the number of wells obtained by aggregating the Company’s working interest in each of its gross wells; and (iii) in relation to the Company’s interest in a property, the total area in which the Company has an interest multiplied by the working interest owned by the Company. “probable reserves” are those additional reserves that are less certain to be recovered than proved reserves. It is equally likely that the actual remaining quantities recovered will be greater or less than the sum of the estimated proved plus probable reserves. “prospective resources” means quantities of petroleum estimated, as of a given date, to be potentially recoverable from undiscovered accumulations by application of future development projects. Prospective resources have both an associated chance of discovery and a chance of development. “proved reserves” are those reserves that can be estimated with a high degree of certainty to be recoverable. It is likely that the actual remaining quantities recovered will exceed the estimated proved reserves. “reserves” are estimated remaining quantities of oil and natural gas and related substances anticipated to be recoverable from known accumulations, as of a given date, based on: (i) analysis of drilling, geological, geophysical and engineering data; (ii) the use of established technology; and (iii) specified economic conditions, which are generally accepted as being reasonable. Reserves are classified according to the degree of certainty associated with the estimates. “risked” means adjusted for the probability of loss or failure in accordance with the COGE Handbook. “undeveloped reserves” are those reserves expected to be recovered from known accumulations where a significant expenditure (for example, when compared to the cost of drilling a well) is required to render them capable of
classification (proved, probable) to which they are assigned. References in this presentation to “2P reserves”, “contingent resources” and “prospective resources”, refer to gross proved plus probable reserves, gross best estimate contingent resources and gross best estimate prospective resources, respectively. Further Economic Assumptions For Nest 1: NGL recoveries and shrinkage factors are based on the company’s best estimate of the liquids to be extracted at the Pembina Kakwa River Plant and at 7G’s wholly owned plants in Alberta, as well as the liquids to be processed by Aux Sable at its facilities near Chicago, Illinois pursuant to the terms of the rich gas premium agreement between 7G and Aux Sable, which depends upon an assumed heating value and has been assumed to extend for the entire productive life of the wells. Nest 1 2018 estimates represent an average of Nest 1 pads brought on- stream in 2018. For a description of the methodology used and the assumptions made by the company in preparing the type-curve forecasts that were used to develop the forecast economics shown on the slide titled “Nest 1 Development – Ultra-Rich Condensate Region” and for important additional information, please see the “Note Regarding Development Area Forecast Economics and Type-Curves” and the “Note Regarding Potential Drilling Opportunities” above. The forecasts for Nest 1 reflect half-cycle economics and include only the cost to drill, complete, tie and equip wells. The forecasts do not take into account certain
costs that would be required to construct infrastructure, including Super Pads, central processing facilities, regional gathering facilities, condensate stabilization facilities and
infrastructure, nor do they take into account land acquisition costs, corporate overhead (G&A) expenses, financing costs or corporate taxes. These forecast economics are intended to represent the marginal return of a single well investment on an existing Super Pad. No adjustments have been made for expected downtime or facility constraints, so the forecasts present an idealistic view of results that could be achieved in the absence
Actual results will differ from these forecasts for the reasons described above and because of the risks and risk factors that are described in the “Forward-Looking Information Advisory” above. Other Definitions Throughout this presentation, 7G uses the terms “sustaining capital” and “discretionary capital”. These measures do not have any standardized meaning and therefore should not be used to make comparisons to similar measures presented by other entities. “Sustaining capital” refers to capital expenditures including drilling, completions, equipping, tie-in and other expenditures required to maintain production from existing facilities at current levels. “Discretionary capital” refers to capital expenditures that are not required to maintain production from existing facilities at current levels, including but not limited to delineation, infrastructure, value-enhancing projects, and production growth.
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A AECO Alliance avg bbl or bbls B or bn Bcf Boe or BOE Btu C* °C CAD or C$ or $ Capex CDN CF CGR CG COLC CO2e COGE Handbook
CROIC C2 C3 C4 C5 or C5+ d D&C DCET DD&A Deep Southwest EBITDA ESG E&P FCF FX G&A G&G GHGe GJ GTN H1 H2 H2S HH or Hhub or Hub Hz IFRS IP IPO IRR ISS Km Kpa LMR LNG LGR annual physical storage and trading hub for natural gas on the TransCanada Alberta transmission system Alliance pipeline average barrels or barrels billion billion cubic feet barrels of oil equivalent British thermal units Alberta drilling and completion cost allowance degrees Celsius Canadian dollars capital expenditures Canadian cash flow condensate/gas ratio citygate Crude Oil Logistics Committee carbon dioxide equivalent the Canadian Oil and Gas Evaluation Handbook maintained by the Society of Petroleum Engineers (Calgary Chapter), as amended from time to time. cash return on invested capital ethane propane butane pentanes plus day drill and complete drill, complete and tie-in depletion, depreciation and amortization the “Deep Southwest” area that is shown in the map in this presentation earnings before interest, taxes, depreciation and amortization environmental, social, and governance exploration & production free cash flow foreign exchange rate general and administrative expense geology and geophysics greenhouse gas equivalent Gigajoule Gas Transmission Northwest LLC first half of the year second half of the year hydrogen sulfide Henry Hub horizontal International financial reporting standards initial production for the number of days specified initial public offering internal rate of return Institutional Shareholder Services kilometres kilopascals liability management rating liquefied natural gas liquid to gas ratio LPG LTIF m Mbbl Mboe Mcf MM MMboe MMbtu MMcf mo N2 NAV NCIB NEB Nest Nest 1 Nest 2 Nest 3 NGL or NGLs NGPL NGTL NPV NYMEX OPEX PDP PIR PP&E psi Q1 or 1Q Q2 or 2Q Q3 or 3Q Q4 or 4Q R&D Rich Gas ROCE ROY SEDAR sh Super Pad TCPL TSX TRIF TTM US USD or US$ Wapiti WCS WCSB WTI YE YTD Y/Y 1P 2P 2C $MM or MM$ Δ liquified petroleum gas lost time incidence frequency metres thousand of barrels thousands of barrels of oil equivalent thousand cubic feet million million barrels of oil equivalent million British thermal units million cubic feet month Nitrogen net asset value normal course issuer bid National Energy Board the Nest 1, Nest 2 and Nest 3 areas combined the “Nest 1” area that is shown in the map in this presentation the “Nest 2” area that is shown in the map in this presentation the “Nest 3” area that is shown in the map in this presentation natural gas liquids Natural Gas Pipeline Company of America pipeline system NOVA Gas Transmission Ltd. pipeline system net present value New York Mercantile Exchange
gross proved developed producing reserves profit to investment ratio property, plant and equipment pounds per square inch first quarter of the year second quarter of the year third quarter of the year fourth quarter of the year research and development the “Rich Gas” area that is shown in the map in this presentation return on capital employed rest of year System for Electronic Document Analysis and Retrieval share decentralized processing plants that separate field condensate and natural gas TransCanada Pipelines Toronto Stock Exchange total recordable incident frequency trailing twelve month United States United Stated dollars the “Wapiti” area that is shown in the map in this presentation Western Canadian Select Western Canadian Sedimentary Basin West Texas Intermediate year-end year to date year-over-year gross total proved reserves gross total proved plus probable reserves gross best estimate contingent resources millions of dollars Change
TSX: VII