CORPORATE PRESENTATION

Transcription

1 TSX: VII.TO CORPORATE PRESENTATION September 2018

2 7G CORPORATE PROFILE Corporate Highlights Premier Alberta Montney Pure-Play Canada s Largest Condensate Producer 69 Mbbl/d of condensate production in Q bbls/mmcf condensate-gas-ratio in Q Diversity of Product Stream and Market Access 37% condensate, 22% NGLs and 41% natural gas in Q Multiple market exposures across product streams Generating Meaningful Returns 12.1% return on capital employed (ROCE) in Q (3) $1.5bn trailing 12 month funds flow (3) Financial Strength 1.5x trailing 12 month net debt to funds flow ratio (3) >$1.2 billion current available funding (3) Capitalization and Q Financial Highlights Ticker symbol - TSX VII Production 187 Mboe/d (59% liquids) Market Cap (1) $5.7 billion Funds from Operations (3) $434 million Net Debt (2) $2.2 billion Realized Price ($/boe) $42.42 Enterprise Value $7.9 billion Operating Netback (3) ($/boe) $28.02 Share Count Basic (1) million Corporate Netback (3) ($/boe) $25.49 (1) August 30, 2018 share price & shares outstanding (2) US$1.575B in senior unsecured notes converted at $ CAD/USD plus adjusted net working capital deficiency and credit facility draws as of June 30, 2018 of $58.0 MM and $131.7 MM respectively (3) Non-IFRS Financial Measure. For additional information see Non-IFRS Measures Advisory in the Important Notice that appears at the end of the presentation 2

3 LEVEL 1 CORPORATE POLICY Stakeholder Differentiation 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 operate an energy project, can be granted and taken away by society. Over the longer term, companies can only expect to thrive if they 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 of present and future generations; The need of Canada and Alberta for us to obey all regulations and to proactively assist with the formulation of new policy that enables our company and our industry to better serve society; The need of our business partners and infrastructure customers to be treated fairly and attentively; 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. 3

4 SEVEN GENERATIONS KEY FOCUS AREAS Profitable Growth Balancing production growth with free cash flow profile Revenue growth driven by increasing liquids production and strong condensate pricing Improving production volatility and risk profile Operational Excellence Consistent execution and business performance Tailored completion designs to improve capital efficiencies Enhancing existing infrastructure, ground logistics, cost structure, and on-stream times Shareholder Returns Consistent, industry-leading returns on capital employed Continued growth of funds flow per share Optimized capital allocation that creates options for return of capital to shareholders Notes: For additional information see Forward Looking Information Advisory and Non-IFRS Measures Advisory in the Important Notice at the end of this presentation. 4

5 CROIC (%) TRACK RECORD OF INDUSTRY LEADING RETURNS AND FUNDS FLOW PER-SHARE GROWTH 7G Quarterly and Annual Funds From Operations per Diluted Share ($/share) (2) $5.00 $4.50 $4.00 $3.50 $3.00 $2.50 $2.00 $1.50 $1.00 $0.50 $0.00 Quarterly FFO per share has increased >2.5X since IPO H1/18 Annualized - $4.48/sh $3.37/sh $2.30/sh $1.46/sh $1.53/sh $1.11 $0.51 $0.61 $0.48 $0.41 $0.35 $0.47 $0.38 $0.39 $0.40 $0.66 $0.64 $0.60 $0.75 $0.73 $0.78 $1.05 $1.19 Q1/14 Q2/14 Q3/14 Q4/14 Q1/15 Q2/15 Q3/15 Q4/15 Q1/16 Q2/16 Q3/16 Q4/16 Q1/17 Q2/17 Q3/17 Q4/17 Q1/18 Q2/18 20% 18% 16% 14% 12% 10% 8% 6% 4% 2% 12% 15% VII Historical Cash Return on Invested Capital (CROIC) (1)(2) 19% 5% 6% 8% Top Canadian Liquids-Rich Gas Peers Industry leading return on capital metrics 7% 6% 9% 9% 2015A 2016A 2017A 2015A 2016A 2017A 2015A 2016A 2017A 2015A 2016A 2017A Top Canadian Gas Weighted Peers Source: CIBC World Markets Peer groups are comprised of: Liquids-Rich - ARX, CR, KEL, NVA Gas AAV, BIR, PEY, PPY, SRX, TOU U.S. Growth AR, COG, EOG, EQT, PXD, RRC, SWN 5% 4% Top U.S. Growth Peers (1) CROIC calculated as FactSet EBITDA divided by gross PP&E. FactSet EBITDA and CROIC are non-ifrs financial measures. (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. 5

6 2018 BUDGET - A PRODUCTION BASE THAT DRIVES FREE CASH FLOW Corporate Production MBOE/d 2018 Guidance (1) Natural Gas Total Production (MBOE/d) Liquids Production (%) 58 60% Condensate Production (%) 35 36% NGL Production (%) 23 24% Natural Gas Production (%) 40 42% NGLs Condensate CGR (bbl/mmcf) LGR (bbl/mmcf) Capital Expenditures ($MM) 1,675 1,775 Funds From Operations ($MM) (2) 1,725 1,775 Growing high value liquids production 1) For additional information see Forward Looking Information Advisory and Non-IFRS measures Advisory in the Important Notice at the end of this presentation. 2) Forecast FFO at US$65/bbl WTI. 6

7 2018 BUDGET: CAPITAL INVESTMENT AND CASH FLOWS 2018 Budget Capital Investment and Funds Flow (1)(2) US$65.00/bbl WTI $1,725 MM $1,775 MM Funds From Operations - Sustaining Capital = Free Cash Flow Funds From Operations US$60.00/bbl WTI $1,600 MM $1,675 MM Investment Priorities 2019 and Beyond Strategic Acquisitions Optimization of Production Growth and Returns of Capital US$55.00/bbl WTI $1,450 MM $1,525 MM Balance Sheet Optimization Capital Investment Development and Delineation $1,475 - $1,575 MM Major Infrastructure $200 MM Sustaining Capital Funds From Operations $0 $250 $500 $750 $1,000 $1,250 $1,500 $1,750 $2,000 WTI pricing drives funds flow and accelerates free cash flow profile 1) For additional information see Forward Looking Information Advisory and Non-IFRS measures Advisory in the Important Notice at the end of this presentation. 2) Assumptions: WTI US$55/bbl low / US$60/bbl mid / US$65/bbl high; US$3.00/MMBtu NYMEX; AECO Basis (US$1.15/MMbtu); USD / CAD $0.78; Dawn Basis (US$0.10/MMbtu); Chicago Basis (US$0.15/MMbtu); Condensate as a % of WTI: 98%; NGLs as a % of WTI: C4 60%, C3 35%; C2 pricing consistent with the Company s processing and marketing agreements. 7

8 FREE CASH FLOW ENHANCEMENTS ($60 WTI) Trajectory of Improvements to Free Cash Flow Generation Cash Flow Pricing Sensitivities Efficiency Gains Free Cash Flow Priorities Significant Free Cash Flow Visibility Today Balance Sheet Optimization Optimization of Production Growth and Returns of Capital Strategic Acquisitions Sustaining Capital Annual Free Cash Flow +US$10/bbl Condensate +US$5/bbl NGL 10% Better Capital Efficiency 5% Decline Rate Mitigation 10% Opex Savings Pricing and efficiency gains are material drivers of free cash flow 1) For additional information see Forward Looking Information Advisory and Non-IFRS measures Advisory in the Important Notice at the end of this presentation. 2) Assumptions: WTI US$65/bbl; US$3.00/MMBtu NYMEX; AECO Basis (US$1.15/MMbtu); USD / CAD $0.78; Dawn Basis (US$0.10/MMbtu); Chicago Basis (US$0.15/MMbtu); Condensate as a % of WTI: 98%; NGLs as a % of WTI: C4 60%, C3 35%; C2 pricing consistent with the Company s processing and marketing agreements. 8

9 Alberta Condensate Production (bbl/d) CONDENSATE PREMIUM PRICING DRIVES RETURNS Alberta s Largest Condensate Producer 350, , , , , ,000 50,000 Other Seven Generations 2018 Alberta condensate demand is estimated to be approx. 550,000 bbl/d 7G condensate production currently accounts for approx. 20% of Alberta supply Source: Peters & Co. Limited Equity Research April 2018 Edmonton Condensate vs. Crude Oil Prices (US$/bbl) $70.00 $60.00 Condensate currently outperforming Permian producer benchmark crude (Midland) $50.00 $40.00 $30.00 $20.00 $ WTI Oil Midland Oil Edm. Condensate WCS Heavy Oil Source: Bloomberg 9

10 7G S NEST MONTNEY DEVELOPMENT AREA 7G Development Area Segmentation Development Inventory (1) ~1,400 Locations across Nest development area: Nest Locations Nest Locations South 140 West 100 North 290 East 170 Nest Locations 2P Reserves: 1.7 billion BOE Contingent Resources (risked): 1.3 billion BOE Prospective Resources (risked): 740 MMBOE Future Development Potential ~900 Wapiti and Rich Gas locations (1) ~800 net Lower Montney sections ~230 net sections of Cretaceous Rights ~120 identified Falher & Wilrich locations (1) 2 Wilrich wells to be tested in 2018 ~315 net Deep Southwest sections Multi decade drilling inventory identified through reserve and resource reports Notes: (1) As of December 31, For additional information see Forward-Looking Information Advisory, Presentation of Oil & Gas Information and Note Regarding Potential Drilling Opportunities in the Important Notice at the end of the presentation. 10

11 DEVELOPMENT AREA FORECAST ECONOMICS Key Stats Nest 1 (2014) Nest 3 Nest 2 South East West North Weighted Average IP30 (boe/d) 1,250 2,000 1,950-2,350 IP365 (boe/d) 675 1,400 1,150-1,650 DCET Cost ($MM) $9.5 $11.0 $ $11.5 IP365 CGR (bbls/mmcf) IRR (%) 55% 90% 125% 175% >300% 250% 220% NPV ($MM) $6.5 $9.5 $10.0 $13.5 $20.0 $15.0 $14.5 Locations (#) ) The following pricing assumptions were used to develop the economic forecasts shown above: $60.00 US/bbl WTI, $2.75 US/mcf NYMEX/HH and 0.78 USD/CAD FX. NGLs as % of WTI: C3 35%, C4 53%, C5 95%. Chicago Basis US$0.30/mcf to NYMEX/HH and AECO Basis US$1.50/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, Nest 1 C$0.30/mcf. Fixed well operating cost = $20,000/mo. 2) 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. 3) 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 in the above table, and for important additional information regarding the type-curve forecasts and the estimated potential drilling opportunities that are reflected above, please see the Note Regarding Development Area Forecast Economics and Type- Curves and the Note Regarding Potential Drilling Opportunities in the Important Notice at the end of this presentation. 4) The forecast economics shown above are half-cycle economics and include only the cost to drill, complete, tie and equip wells. The forecasts do not 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 other 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 of additional infrastructure costs, operational challenges or downtime. 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 in the Important Notice at the end of this presentation. 5) The drilling locations reflect the estimated number of drilling opportunities as at December 31, 2017, some of which have been drilled in ) Net Present Value (NPV) is calculated based on a 10% annual discount factor. 11

12 CONTINUOUS COMPLETION DESIGN INNOVATION Nitrogen Foam Completions Slickwater Completions High Intensity Slickwater Completions Increased Stages, Less Tonnage per stage Tailored to Regional Attributes & Beyond Initial early stage N 2 foam completion 28 stage, 120 tonnes per stage design Similar results as N 2 foam completions Increased stage count, sand intensity and cost Increased tonnage and stage count, cemented liner Higher intensity completion to maximize recovery Optimized proppant placement with higher stage counts Increased fracture entry points across wellbore Integration of subsurface studies into completions design Customized frac intensity for optimal rates and recoveries Regionally tailored completions drive maximized capital efficiency 12

13 MARKET ACCESS PRODUCT AND LOCATION DIVERSITY Product and Geographical Diversity 2018 Forecasted Revenue by Product (1)(2) Condensate Close proximity to major demand centre (oil sands) Alberta condensate trades in-line with WTI pricing Only Canadian product stream without substantial discount to U.S. benchmarks NGLs (Ethane, Propane, Butane) 10% 29% 61% Diversity of product mix (ethane, propane & butane) Approximately 50/50 split between Alberta & U.S. Midwest NGL markets Natural Gas Condensate NGLs Natural Gas Gas Market Diversification Over 80% of gas sales marketed outside of Alberta Alliance: U.S. Mid-West (Chicago Citygate) GTN: U.S. Pacific NW (Malin ) NGPL: U.S. Gulf Coast (Henry Hub) TCPL: Eastern Canada (Dawn) & Alberta (AECO) Higher value condensate and NGL barrels cannot be produced without gas, so firm transportation ensures revenue capture for liquids Market Access Initiatives Evaluation and execution of greenfield marketing opportunities Includes petrochemical, LNG,LPG export, gas fired power generation Source: ARC Financial Note: 1) Volumes represent 2020 commitment levels 2) Transportation commitments are not additive 1) Assumptions: US$60/bbl, $0.81 USD/CAD, NYMEX HH price of US$3.00/MMbtu, Chicago CG basis of -US$0.15/MMbtu, AECO basis of -US$1.15/MMbtu. 2) Notes: For additional information see Forward Looking Information Advisory in the Important Notice at the end of this presentation. 13

14 INFRASTRUCTURE SUMMARY Infrastructure Footprint Natural Gas Processing: 760 MMcf/d capacity 510 MMcf/d owned & operated Access to 3rd party capacity of up to 250 MMcf/d Building an additional 250 MMcf/d at Gold Creek Condensate Stabilization: 80 mbbl/d capacity 60 mbbl/d owned & operated Access 3rd party capacity of up to 20 mbbl/d Integrated processing, gathering and distribution infrastructure across entire land base 14

15 Processsing Capacity (MMcf/d) CANADIAN PEER PROCESSING CAPACITY 1,600 Owned and Operated Natural Gas Processing Capacity (MMcf/d) 1,400 1,200 1, A B C D 7G E F G H I J K L M 1 Source: Scotiabank Global Banking and Markets 2 Peer group includes: Advantage, ARC, Cenovus, Encana, Husky, Paramount, Peyto, Progress, Repsol, Shell, TAQA, Torxen, Tourmaline 7G s owned and operated processing capacity is among the largest in the WCSB 15

16 BEYOND THE NEST MULTIPLE HORIZON DEVELOPMENT POTENTIAL Spirit River ~230 net sections with ~120 locations identified (Falher, Wilrich, etc.) Two minority interest Wilrich wells (12.5% 7G) drilled in 2017 with average first-month IP rates of ~16.5 MMcf/d Upper/Middle Montney 790 net sections, primary focus of 7G development, generating >90% of current corporate production >2,000 development locations across the Nest, Wapiti & Other Areas Lower Montney 790 net sections, contiguous with Upper/Middle Montney development area Negligible reserves or resources attributed with significant upside potential Duvernay Significant drilling activity in the formation from other operators 402 net sections, not contemplated in current development plans Note: For illustrative purposes, not to scale. Multi-horizon development utilizing existing 7G infrastructure drives half-cycle returns Notes: For additional information see Forward Looking Information Advisory, Note Regarding Potential Drilling Opportunities and Non-IFRS Measures Advisory in the Important Notice at the end of this presentation. 16

17 THE 7G VALUE PROPOSITION Asset Quality Among North America s lowest supply cost oil and condensate producers Canada s largest condensate producer Inventory ~ 800 net sections of Montney rights with decades of drilling opportunities ~1,400 drilling opportunities within the Nest core development area Balance Sheet Conservative balance sheet with ample liquidity A consistent risk management program to ensure consistent returns Market Diversity A diversified product mix with exposures across North America A natural gas marketing portfolio with multiple egress options Operational Excellence Renewed focus on cost-effective resource development Managing downtime, logistics and safety Effective Capital Allocation Track record of consistent per-share production and funds flow growth Multiple options for free cash flow allocation to maximize shareholder value Notes: For additional information see Forward Looking Information Advisory, Note Regarding Potential Drilling Opportunities and Non-IFRS Measures Advisory in the Important Notice at the end of this presentation. 17

18 Appendix 18

19 CURRENT HEDGE POSITION Hedge Position June 30, Q Q H Q Q Q Q Q Q Q Q Q Q H Liquids Hedging Total WTI Hedged - bbl/d 35,000 34,000 34,500 34,000 30,000 28,000 22,000 28,500 22,000 20,000 18,000 14,000 18,500 8,000 3,000 5,500 CAD WTI Hedged - bbl/d 31,000 30,000 30,500 30,000 26,000 22,000 16,000 23,500 12,000 10,000 8,000 4,000 8, CAD WTI Average Bought Put (Floor) - C$/bbl $58.39 $58.17 $58.28 $58.17 $57.88 $58.18 $58.13 $58.09 $57.50 $57.00 $56.25 $57.50 $57.06 $0.00 $0.00 $0.00 CAD WTI Average Sold Call (Ceiling) - C$/bbl $76.42 $76.44 $76.43 $76.44 $75.83 $76.11 $74.90 $75.93 $72.81 $71.38 $70.28 $70.33 $71.50 $0.00 $0.00 $0.00 CAD WTI Puts Sold - bbl/d** 12,000 12,000 12,000 12,000 10,000 6,000 2,000 7,500 2,000 2,000 2, , CAD WTI Average Sold Put - C$/bbl** $40.83 $40.83 $40.83 $40.83 $41.00 $41.67 $40.00 $41.00 $40.00 $40.00 $40.00 $0.00 $40.00 $0.00 $0.00 $0.00 USD WTI Hedged - bbl/d 4,000 4,000 4,000 4,000 4,000 6,000 6,000 5,000 10,000 10,000 10,000 10,000 10,000 8,000 3,000 5,500 USD WTI Average Bought Put (Floor) - US$/bbl $53.57 $53.57 $53.57 $53.57 $53.57 $52.38 $52.38 $52.85 $52.48 $52.48 $52.48 $52.48 $52.48 $52.53 $53.50 $52.80 USD WTI Average Sold Call (Ceiling) - US$/bbl $57.94 $57.94 $57.94 $57.94 $57.94 $58.58 $58.58 $58.32 $59.38 $59.38 $59.38 $59.38 $59.38 $59.90 $60.75 $60.13 USD WTI Puts Sold - bbl/d** ,000 1,000 1,000 1,000 1,000 1,000 1,000 1,000 USD WTI Average Sold Put - US$/bbl** $0.00 $0.00 $0.00 $0.00 $0.00 $0.00 $0.00 $0.00 $40.00 $40.00 $40.00 $40.00 $40.00 $40.00 $40.00 $40.00 Natural Gas Hedging Total Gas Hedged - MMbtu/d 266, , , , , , , , ,478 89,478 69,478 69,478 94,478 40,000 10,000 25,000 Gas Hedged - NYMEX HH - MMbtu/d 60,000 60,000 60,000 70,000 70,000 70,000 70,000 70,000 90,000 40,000 40,000 40,000 52,500 40,000 10,000 25,000 Average NYMEX HH Swap - USD/Mmbtu $2.95 $2.95 $2.95 $2.92 $2.92 $2.92 $2.92 $2.92 $2.90 $2.81 $2.81 $2.81 $2.85 $2.81 $2.73 $2.79 Gas Hedged - Chi CG - MMbtu/d 150, , , , , ,000 80, ,500 50,000 40,000 20,000 20,000 32, Average Chi CG Swap - USD/MMbtu $2.85 $2.84 $2.84 $2.83 $2.87 $2.84 $2.83 $2.84 $2.76 $2.73 $2.71 $2.71 $2.74 $0.00 $0.00 $0.00 Gas Hedged - AECO - GJ/d 60,000 60,000 60,000 60,000 60,000 60,000 60,000 60,000 10,000 10,000 10,000 10,000 10, Average AECO Bought Put (Floor) - C$/GJ $2.44 $2.44 $2.44 $2.44 $2.44 $2.44 $2.44 $2.44 $2.13 $2.13 $2.13 $2.13 $2.13 $0.00 $0.00 $0.00 Average AECO Sold Call (Ceiling) - C$/GJ $2.85 $2.85 $2.85 $2.85 $2.85 $2.85 $2.85 $2.85 $2.13 $2.13 $2.13 $2.13 $2.13 $0.00 $0.00 $0.00 Natural Gas Basis Hedging Basis Hedged - Chi CG - GJ/d ,000 2,500 40,000 40,000 40,000 40,000 40,000 40,000 20,000 30,000 Average Chi CG Basis Swap - US$/MMbtu $0.00 $0.00 $0.00 $0.00 $0.00 $0.00 -$0.23 -$0.23 -$0.23 -$0.23 -$0.23 -$0.23 -$0.23 -$0.23 -$0.23 -$0.23 FX Hedging FX Forwards USD Notional Hedged ($MM) $60.3 $57.5 $117.7 $46.1 $46.4 $38.7 $30.7 $69.4 $27.4 $24.8 $19.8 $19.8 $39.7 $14.9 $14.9 $29.7 Average Rate FX Collars USD Notional Hedged ($MM) $2.5 $2.5 $5.0 $2.5 $5.0 $5.0 $5.0 $9.9 $5.0 $5.0 $5.0 $5.0 $9.9 $5.0 $5.0 $9.9 Average Rate Bought Put (Floor) Average Rate Sold Call (Ceiling) **Represents volumes and prices for additional puts sold for 3-way WTI collars 19

20 SELECTED FINANCIAL AND OPERATIONAL INFORMATION VII - Recent Quarterly Results OPERATING RESULTS Q Q Q Q Q Q Q Q Q Q YE 2017 YE 2016 Average daily production (1) Condensate (mbbl/d) Natural gas (MMcf/d) NGLs (mbbl/d) Total (mboe/d) CGR Ratio LGR Ratio Realized Prices Condensate ($/bbl) Natural gas ($/Mcf) NGLs ($/bbl) FINANCIAL RESULTS (4) Condensate ($MM) , Natural gas ($MM) NGLs ($MM) Liquids and natural gas sales (1)(2) ($MM) , ,246.9 Royalties ($MM) (16.4) (18.9) (21.5) (14.5) (9.3) (16.8) (11.9) (0.4) 18.6 (13.0) (62.1) (6.7) Operating expense ($MM) (102.2) (96.8) (103.3) (91.8) (93.9) (68.8) (59.1) (47.0) (44.8) (31.0) (357.8) (181.9) Transportation, processing and other expense ($MM) (118.0) (105.4) (116.8) (109.4) (88.3) (74.3) (77.0) (77.9) (57.5) (39.9) (388.8) (252.3) Netback prior to hedging ($MM) , Realized hedging gain (loss) ($MM) (17.7) (13.1) (7.2) Marketing Income (3)(5) ($MM) Netback after hedging ($MM) , General and administrative expense ($MM) (13.9) (10.9) (11.8) (11.0) (12.3) (10.9) (14.1) (7.6) (10.0) (8.0) (46.0) (39.7) Finance expense and other ($MM) (29.1) (29.8) (35.4) (39.4) (41.0) (41.6) (38.8) (39.1) (26.9) (26.1) (157.4) (130.9) Funds from operations (3) ($MM) , Netbacks (4) Oil and natural gas revenue ($/boe) Royalties ($/boe) (0.96) (1.12) (1.18) (0.86) (0.62) (1.22) (0.98) (0.03) 1.74 (1.61) (0.97) (0.16) Operating expense ($/boe) (6.00) (5.73) (5.69) (5.43) (6.25) (4.99) (4.86) (3.85) (4.19) (3.85) (5.60) (4.22) Transportation, processing and other expense ($/boe) (6.93) (6.24) (6.43) (6.47) (5.87) (5.39) (6.33) (6.39) (5.38) (4.95) (6.09) (5.85) Operating netback prior to hedging ($/boe) Realized hedging gain (loss) ($/boe) (1.04) (0.78) (0.52) Marketing Income (3)(5) ($/boe) Operating netback (3) ($/boe) General and administrative expense ($/boe) (0.82) (0.65) (0.65) (0.65) (0.82) (0.79) (1.16) (0.62) (0.94) (0.99) (0.72) (0.92) Finance expense and other ($/boe) (1.71) (1.76) (1.95) (2.33) (2.73) (3.02) (3.19) (3.20) (2.52) (3.24) (2.46) (3.04) Funds flow netback (3) ($/boe) Capital investments Drilling and completions ($MM) , Facilities and infrastructure ($MM) Land and other ($MM) Total capital investments (4) ($MM) , ) Starting in 2018, Seven Generations began presenting C5+ in the NGL mix as a condensate volume (previously reported as an NGL volume) and 2016 liquids and natural gas sales have been adjusted to confirm to this current period presentation. 2) Excludes the purchase and resale of condensate and natural gas in respect of the Company's transportation commitment optimization and marketing activities. Refer to the Company's Q MD&A as filed on SEDAR for additional information. 3) Figure is a non-ifrs financial measure. Refer to the Company's Q MD&A as filed on SEDAR for additional information. 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 gas, net of applicable pipeline tariffs, represent the margins earned in respect of the Company's transportation optimization and marketing activities. 20

21 SWEET SPOT OF THE MONTNEY Over Pressured High Productivity Brittle Rock High Recovery Factor Thickness Large Resources in Place Lower Temperature High Liquids Content 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 21

22 RESPONSIBLE DEVELOPMENT HIGHLIGHTS Safety Environment Community Safety first 0.64 TRIF in 2017 Building a culture of safety Total Recordable Incident Frequency up 14% Lost-Time Incident Frequency down 40% Low GHGs GP Hospital carbon intensity (1) $1.7 million raised Among lowest carbon intensity of Canadian producers Independent verification: Leak Detection and Repair Program clearly working to reduce methane emissions, says Stanford researcher 7G s annual golf tournament raised $1.7 million for the GP Regional Hospital Foundation in its first five years (1) Based upon 2016 data. Represents estimated metric tonnes of carbon dioxide equivalent per barrel of oil equivalent of production. 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. 22

23 IMPORTANT NOTICE General Advisory The information contained in this presentation does not purport to be allinclusive 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 entire 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 or different information, and any such information, including statements in media articles about Seven Generations, should not be relied upon. In this presentation, unless otherwise indicated, all dollar amounts are expressed in Canadian dollars, and 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 oil and gas industry and, more specifically, the shale and tight liquids-rich 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 working capital, operating netback, corporate netback, funds from operations (also referred to herein as funds flow ), net debt, adjusted EBITDA, return on capital employed (or ROCE ), Factset EBITDA, cash return on invested capital (or CROIC ) and marketing income, 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 working capital, operating netback (also referred to herein as netback ), funds from operations (also referred to herein as funds flow ), net debt, adjusted EBITDA, return on capital employed (or ROCE), marketing income, and reconciliations between those measures and the most directly comparable measures under IFRS for the most recently completed quarter, see Non-IFRS Financial Measures in the Company s Management s Discussion and Analysis dated August 1, 2018 for the three and six months ended June 30, 2018 and 2017, which is available on the SEDAR website at FactSet EBITDA is calculated by a third party and differs from adjusted EBITDA primarily through the exclusion of realized hedging gains and losses. Cash return on invested capital (or CROIC ) is FactSet EBITDA divided by the average unamortized cost of developed and producing oil and natural gas assets and is a performance measure of a company s ability to generate returns on capital investments. The 2017 CROIC of 19% reflects FactSet EBITDA of $1,341.5 million divided by the average cost of oil and natural gas assets of $7,213.5 million. The 2016 CROIC of 15% reflects FactSet EBITDA of $757.9 million divided by the average cost of oil and natural gas assets of $5,104.6 million. The 2015 CROIC of 12% reflects FactSet EBITDA of $334.2 million divided by the average cost of oil and natural gas assets of $2,769.9 million. 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 priorities, objectives and competitive strengths; the Company s development plans; intention to balance production growth with per share profitability; the planned optimization of capital allocation to facilitate operational improvements; plans to tailor completion designs to address regional reservoir characteristics, leading to improve capital efficiencies; plans to moderate production decline rates and reduce future production volatility; efforts to maximize netbacks, profit margins and returns on capital deployed; guidance and outlooks, including expected production, production composition, CGRs, LGRs, anticipated liquids yields, capital investment, funds from operations and future revenue; investment priorities for 2019 and beyond; improvements and other variables that are expected to lead to free cash flow; the decades of drilling opportunities that are expected from the company s properties; drilling locations; gas processing, condensate stabilization and transportation capacity; upside development potential of various formations and secondary targets; expectation that the utilization of 7G infrastructure may provide halfcycle returns from the development of secondary targets; forecasted NPVs and IRRs; expected costs and supply-costs; processing capacity expected from the new gas plant in the Gold Creek area, currently under construction; 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 within the Kakwa River Project; 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; the 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 operations, royalties, taxes and environmental matters in the jurisdictions in 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 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 of funding; the Company s future debt levels; geological and engineering estimates in respect of the Company s reserves and resources; the geography of the areas in which 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. Assumptions made in the calculation of forecasted economics, including forecasted NPVs, IRRs, price sensitivities, commodity prices and recovery factors are provided in footnotes proximate to those disclosures. 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 opportunities that are referenced herein, various assumptions have been made. These assumptions are described under the heading Note Regarding Potential Drilling Opportunities below. Actual results could differ materially from those anticipated in forward-looking information as a result of the risks and risk factors that are set forth in the Company s Annual Information Form dated March 13, 2018 (the AIF ), which is available on SEDAR at 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; 23

24 IMPORTANT NOTICE 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; changes in laws or regulations, including those pertaining to royalties or taxation; 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; adoption or modification of climate change legislation by governments; the absence or loss of key employees; 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 processing facilities, compressors, gathering lines, pipelines and other facilities, certain of which the Company does not control; the ability to satisfy obligations under the Company s firm commitment transportation arrangements; the uncertainties related to the Company s identified drilling locations; the highrisk nature of successfully stimulating well productivity and drilling for and producing oil, NGLs and natural gas; operating hazards and uninsured risks; risk of fires, floods and natural disasters; 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 area; unforeseen title defects; aboriginal claims; failure to accurately estimate abandonment and reclamation costs; development and exploratory drilling efforts and well operations may not be profitable or achieve the targeted return; horizontal drilling and completion technique risks and failure of drilling results to meet expectations for reserves or 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 obtain protection from sellers against such liabilities; changes in the application, interpretation and enforcement of applicable laws and regulations; restrictions on drilling 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 Canadian 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; 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; security deposits required under provincial liability management programs; reassessment by taxing authorities of the Company s prior transactions and filings; variations in foreign exchange rates and interest rates; third-party credit risk including risk associated with counterparties in risk management activities related to commodity prices and foreign exchange rates; sufficiency of insurance policies; potential litigation; variation in future calculations of non- IFRS measures; sufficiency of internal controls; 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, including the potential inability to comply with the covenants in the credit agreement related to the Company s credit facilities and/or the covenants in the indentures in respect of the Company s senior unsecured notes. Financial outlook and future-oriented financial information contained in this presentation regarding prospective financial performance, financial position, cash flows or well economics is 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 material. Actual results will vary from projected results. Financial outlook 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 or verified by the Company. Presentation of Oil and Gas Information Estimates of the Company s reserves, contingent resources and prospective resources contained herein are based upon the reports dated March 13, 2018 prepared by McDaniel & Associates Consultants Ltd. ( McDaniel ), the Company s independent qualified reserves evaluator, as at December 31, 2017 (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 discovered. If discovered, there is no certainty that it will be commercially 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 of contingent resources and prospective resources, as at December 31, 2017, that have been risked by McDaniel for the probability of loss or failure in accordance with the COGE Handbook. For contingent resources, the risk component relating to the 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, 2017, in the upper and middle intervals of the Montney formation in certain parts of the Nest 1, Nest 2, Nest 3, Rich Gas and Wapiti areas. 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 development. Contingent resources in the development unclarified project maturity subclass have been assigned by McDaniel, as at December 31, 2017, in the lower interval of the Montney formation in the northwest corner of the Wapiti 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 uncertainties. These resource estimates are not classified as reserves at this time, pending further reservoir delineation, project application, facility and reservoir design work. There is uncertainty that it will be commercially viable to produce any portion of the contingent resources. Prospective resources have both an associated chance of discovery and a chance of development. Not all exploration projects will result in discoveries. The chance that an exploration project will result in the 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 development. McDaniel has subclassified the prospective resources that were evaluated, as at December 31, 2017 by maturity status, consistent with the requirements of the COGE Handbook. The prospective resources associated with the upper and middle intervals of the Montney formation in the Deep Southwest and Wapiti areas of the 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. The prospective resources associated with the lower interval of the Montney formation across the Project area (with the exception of lower Montney properties in the Wapiti area that have been attributed development unclarified contingent resources by McDaniel) have been sub-classified as lead by McDaniel, which the COGE Handbook defines as a potential accumulation within a play that requires more data acquisition and/or evaluation in order to be classified as a prospect. 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 SEDAR at 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. 24