providing responsibly developed energy to the world · presentation are estimates only and there is...

1©2020 Seven Generations Energy Ltdwww.7genergy.com

TSX: VII

Providing Responsibly Developed Energy to the World

August 2020

2©2020 Seven Generations Energy Ltd

CANADA’S LARGEST

PRODUCER OF

CONDENSATE• Canada’s premiere hydrocarbon product

• Structurally short market drivessignificant import requirements

• Nearly 500 MMcf/d of natural gas sales• Market access across North America

• $3.4B Enterprise Value (1)(2)(3)

• $1.2 B market cap, $2.2 B net debt(3)

• 333 MM shares outstanding

• 183 thousand boe/d(4) in Q2/20(35% condensate, 22% other NGLs, 43% gas)

• A business model focused on responsible development and growing free cash flow

OVERVIEW REVISED BUDGET FINANCIAL HIGHLIGHTS SUSTAINABILITY APPENDIXSTRATEGY ASSET OVERVIEW

1) July 28, 2020 share price & shares outstanding as of June 30, 2020.2) US$1.375B in senior unsecured notes converted at $1.3362 CAD/USD plus adjusted net working capital deficiency and long-term lease liabilities as of June 30, 2020 of $52.8 MM, and $298.2 MM of credit facility draws3) For additional information see “Non-GAAP Measures Advisory” in the “Important Notice” that appears at the end of the presentation.4) For additional information see “Note Regarding Product Types” in the “Important Notice” that appears at the end of this presentation.


SEVEN GENERATIONS ENERGYPositioned to add value through:

Returns focusedThinking like an owner

Deep inventory lifeNearly 20 years of core development

with emerging lower Montney

CultureEntrepreneurial, engaged

& responsible

Best in class assetsLargest producer of condensate –

Canada’s premiere product

OptionalityFrom market access, operatorship,

commodity mix, free cash flow

Operational excellenceContinuous improvement, cost

mindfulness and efficiency



2020 Revised Capital Budget & Guidance

Total Capital Investment $650 million

Average Production 175 – 185 Mboe/d

Development Wells On-Stream (#) 65 – 70

Percent Natural Gas 42 – 44%

Percent Condensate 32 – 36%

Percent Other NGLs 22 – 24%

Royalty Rate 4 – 6%

Operating Expenses ($/boe) $4.50 – $5.00

Transportation ($/boe) $7.50 – $8.25

G&A ($/boe) $0.85 – $0.95

Interest ($/boe) $1.80 – $2.00

$650 Million

1) For additional information, see “Forward-Looking Information Advisory” and “Note Regarding Product Types” in the “Important Notice” at the end of this presentation.

2020 BUDGET DETAILSOrganically funded at strip pricing

Drilling

Completions

Equip& Tie

Pads& Pipes

Other

Nest 2

Nest 1

Nest 3



US$379MM6.75%

US$296MM6.875%

US$700MM5.375%

$0

$100

$200

$300

$400

$500

$600

$700

$800

2020 2021 2022 2023 2024 2025

Fixed Coupon Senior Unsecured Notes

RISK MANAGEMENT

1) As of June 30, 20202) For additional information, see “Forward-Looking Information Advisory” and “Non-GAAP Measures Advisory” in the “Important Notice” at the end of this presentation.

Financial leverage & liquidity are favorable and in compliance with all covenants

additional liquidityfrom credit facility

$1.1Billion

0.0x

0.5x

1.0x

1.5x

2.0x

2.5x

3.0x

3.5x

$30 WTI $40 WTI $50 WTI $60 WTI

Favorable Total Leverage2020E net debt to trailing 12-month adjusted EBITDA

To first maturityCall premiums step down to par in mid-2021

3 Years

- $1.1 B available on $1.4 Bsenior secured credit facility(1)

- Q2/20 draw of C$298 MM- $0.5 B additional accordion option- Late 2024 renewal date


Credit facility covenants: (Trailing 12 month debt metric only includes credit facility draws)

< 3.0x Credit Facility Draw / Adjusted EBITDA ratio> 2.5x total Adjusted EBITDA / Interest coverage ratio

Ratios were 0.2x and 9.3x as at June 30, 2020


RISK MANAGEMENT

1) For additional information, see “Forward-Looking Information Advisory” and “Note Regarding Product Types” in the “Important Notice” at the end of this presentation.

Commodity hedging

Capital investment

Protect

Revenue volatility

Reduce

Balance sheet

Preserve

2020E CondensateBalance of Year

2020E Natural GasBalance of Year

~85%

Hedged at~US$45/bbl

Hedged

Un-hedgedUn-hedged

Hedged

>36%

Hedged at~US$2.60/MMBtu



OPERATIONAL EXCELLENCEPursuing innovations that drive long-term improvements to the business and free cash flow

1) For additional information see “Forward-Looking Information Advisory” and “Non-GAAP Measures Advisory” in the “Important Notice” that appears at the end of the presentation.

$3.00

$3.50

$4.00

$4.50

$5.00

$5.50

$6.00

$6.50

2017 2018 2019 2020EOriginalBudget

2020ERevisedBudget

Operating Costs($ per boe)

$2.0

$2.5

$3.0

$3.5

$4.0


2020ERevisedBudget

Drilling Costs($MM per well)

$2

$3

$4

$5

$6

$7

$8


2020ERevisedBudget

Completion Costs($MM per well)



DRIVING FUTURE SHAREHOLDER RETURNSExpanding free cash optionality

1) Funds flow reflects US$2.50/MMbtu Henry Hub, US$5/bbl condensate differentials. 2) 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. 3) Share counts reflect diluted weighted average shares outstanding for each respective year, with 2020 assuming the company repurchases no additional shares under the company’s normal course issuer bid subsequent to the first quarter of 2020. 4) For additional information, see “Forward-Looking Information Advisory” and “Non-GAAP Measures Advisory” in the “Important Notice” at the end of this presentation.

SustainingCapital Sustaining

Capital

Growth

Major Infra

Delineation

Delineation

Value Enhancing

Value Enhancing

$30 WTI

$40 WTI

$50 WTI

$60 WTI

$70 WTI

$0

$400

$800

$1,200

$1,600

2018 Actual 2019 Actual 2020 Budget 2021 Budget 2022 Budget Funds Flow Sensitivity

2020 Capital

Annual unhedged free cash flow potential by 2022

With a long inventory runway

Substantial

364MillionShares Outstanding(3)



91WellsOn Production

83WellsOn Production

65-70WellsOn Production



CLICK TO EDIT MASTER TITLE STYLE

Environment Social

Total economic contribution to Western Canada in 2019(4)

$2.7Billion

Hours of employee volunteerism from ~250 staff in 2019

10,000+

Drop in Total Recorded Incident Frequency (TRIF) in 2019

57%

Governance

Independent Board Chair

Independent Board Members(1)

90%

Board and CommitteeMeeting Attendance

100%

FOCUSED ON SUSTAINABILITYWhat Gets Measured,

Gets Managed

Truckloads of reduced water transportation in 2018

85,000

Better than industry average Liability Management Rating (LMR)

3.2x

Alignment from supply chain, focused on safety and local providers

Values

1) Marty Proctor, Chief Executive Officer, is the only non-independent director.2) Based upon 2018 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, PEY, SU, VET, WCP3) The peer companies in the Liability Management Rating chart include ARX, BIR, CNQ, CVE, CPG, ECA, ERF, HSE, MEG, PEY, TOU, VET, WCP.4) Total economic contribution is the sum of capital investment, operating expenditures, transportation expenditures, royalties, general & administrative expenditures and other expenditures during 2019

Top-tier carbon disclosure within Canadian oil & gasA-

Lower per-boe GHGefootprint than industry average(2)

80%



• Nest 2Primary Liquids-Rich Region

• Nest 3High-Deliverability Natural Gas Weighted Region

• Nest 1Ultra-Rich Condensate Region

Infrastructure Footprint

Natural Gas Processing:

• ~1 Bcf/d capacity

• 760 MMcf/d owned & operated at Cutbank/Lator/Gold Creek

• 250 MMcf/d of 3rd party capacity access

Condensate Stabilization:

• >80 Mbbl/d capacity

• >60 Mbbl/d owned & operated

• Access 3rd party capacity of up to 20 Mbbl/d

1) For additional information, see “Forward-Looking Information Advisory” in the “Important Notice” at the end of this presentation.

Three core operating regions

Alliance

NGTL


A WORLD-CLASS ASSET ON WHICH WE’VE BUILT THE COMPANY


CANADIAN CONDENSATE FUNDAMENTALS

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.4) Forecast includes the impact of GEI/USD Diluent Recovery Unit assuming 2021 on-stream date

0

200

400

600

800

Forecast Condensate Supply & Demand

(Mbbl/d)(3)(4)

• Total demand of 700+ Mbbl/d exceeds local supply by ~275 Mbbl/d

• Short-term supply/demand and price dislocations resolve quickly from reduced imported volumes

• Canadian condensate continues to price in a range similar to US WTI and Midland streams

$0

$20

$40

$60

$80

2015 2016 2017 2018 2019 2020

Edmonton Condensate vs. Crude Oil Prices(US$/bbl)(2)

WTI Oil Edm. Light Midland Oil WCS Heavy Oil Edm. Condensate

~275 Mbbl/d gap between

supply & demand

2018 2019 2020E 2021E 2022E

Demand

WCSB Supply

Condensate is Canada’s premium liquids product



1,316Upper/MiddleNest Montney

504MontneyDrilled to Date

>256Lower Montney

>250Rich Gas

>160Wapiti

Typical 1-Year Drilling Program

1) Economic assumptions above reflect budgeted price assumptions, which include US$40/bbl WTI and US$2.50/Mmbtu Henry Hub. Economics above reflect a contemporary -US$3/bbl Edmonton condensate discount, versus -US$8/bbl at the time of the May revised budget..2) Full cycle development reflects the scheduling of a hypothetical 72-well development program over time, including the cost of super-pads, satellite pads, water infrastructure, and other go-forward costs in excess of single-well costs, including the effects of downtime, other factors and

associated G&A costs. Full cycle development excludes the investment in natural gas plant construction which has already been materially completed by the company. 3) For additional information, see “Forward-Looking Information Advisory” and “Note Regarding Potential Drilling Opportunities”, “Note Regarding Development Area Forecast Economics and Type-Curves” and “Note Regarding Product Types” in the “Important Notice” at the end of this

presentation. Inventory counts and economics are based on year-end 2019 estimates. 4) PIRs reflect the NPVs divided by the DCET Costs (taken as the midpoint where ranges are provided).

ECONOMICS AND INVENTORYNearly 20 years of core inventory, plus future upside

Core Development Areas (Upper/Middle Montney Only, US$40 WTI/$2.50 Hub, US$3 Condensate Diff)

Nest 1 Nest 2 Nest 3Total /

Average

We

ll A

ttri

bu

tes

IP30 (boe/d) 1,400 1,900 2,000 1,700

IP365 (boe/d) 750 1,000 1,400 950

Cost (DCET) $8.0 MM $8.0 MM $8.0 MM $8.0 MM

Capital Efficiency ($/boe/d)

$10,700 $8,000 $5,700 $8,400

CGR (IP365)

(bbl/mmcf)300 170 55 210

% Condensate (IP365)

64% 50% 25% 53%

Ec

on

om

ics Single

Well(1)

NPV $7.3 MM $8.6 MM $9.7 MM $8.2 MM

IRR 83% 113% 124% 102%

PIR 0.9x 1.1x 1.2x 1.0x

FullCycle(2)

NPV $3.6 MM $4.1 MM $4.8 MM $4.0 MM Emerging Development AreasIRR 37% 43% 61% 43% Lower

MontneyWapiti

Rich Gas

CretaceousPIR 0.4x 0.5x 0.6x 0.5x

Lo

ca

tio

ns Undeveloped 2P 386 452 128 966 6 0 0 0

Contingent 2C 152 168 30 350 >250 >160 >250 >60

Total Locations 538 620 158 1,316 >256 >160 >250 >60

2020 Wells ~3 ~49 ~11 ~63 ~7



TSX: VII

www.7genergy.com

TSX: VII


GUIDING PRINCIPLEWe exist to serve the needs of our stakeholders

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 our business partners and infrastructure customers to be treatedfairly and attentively;

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 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;

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.



Chicago49% 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

NATURAL GAS MARKETINGSOLUTIONS

1) Revenue mix is before hedges and is based on 2020 Q1 actuals and balance of year at strip pricing as of April 25, 2020, averaging approximately US$29 WTI, US$2.00 Henry Hub and 0.72 USD/CAD2) 2019 average benchmark prices sourced from Bloomberg.

• Nearly 700 MMcf/d of take-away outside of Alberta

• Diversified market access supports price optionality

NGPL155 MMcf/d

Alliance500 MMcf/d

TCPL77 MMcf/d

GTN90 MMcf/d

Natural Gas

Condensate

NGLs

2020 Revenue Mix(1)

$0.00

$1.00

$2.00

$3.00

Chicago Gulf Malin Dawn AECO

2019 Benchmark Prices(2)

(US$/MMbtu)



NEST 1

• Emerging development area with high condensate weighting

• Q4/19 land swap enabled optimized development plant

• Offsetting industry activity validates significant productivity

• Increased activity levels planned upon normalization of WTI / condensate pricing

Ultra-rich condensate region

IP94 1,730 boe/d44% Condensate

Flowtest IP20 (7 Hz)1,068 – 1,972 boe/d~63% Condensate

IP60 (2 Hz) 1,413 – 1,963 boe/d~64% Condensate




7G IP60 (Restricted Rates)~1,898 boe/d

72% condensate

Competitor Well Rates

1) For additional information, see “Forward-Looking Information Advisory”, “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.



NEST 2

• 7G’s first major development area

• Geological model refined in 2018 to de-risk development planning

• Regional nuances in condensate/gas mix better understood

• Favorable trends in condensate recoveries

• Recent expansion of boundaries west

• 100 Hz upper/middle Montney locations

• Validated as sweet, liquids-rich condensate locations analogous to North-West Nest 2

Primary liquids-rich region2019 year-end expansion

of Nest 2 boundaries




NEST 3

• 2019 saw large-scale development

• Initial infrastructure and river crossing completed

• Single Super-Pad / hub & spoke style build-out

• Potential to expand boundaries to the south into Rich Gas region

High-deliverability natural gas weighted region




2,8

00

-3,0

00

me

ters

20

0m

etr

es

800 metres

Upper Montney

Middle Montney

Lower Montney

LOWER MONTNEY

• Successful Q3/18 to Q4/19 delineation efforts

• Validated productivity and reservoir characteristics

• 6 successful Hz wells with varying completions intensity and design

• Triple-stack development model pilot

• Stacked development layer expands resource& improves surface infrastructure utilization

• Up to 50% more inventory per section(2)

• 30% increased NPV per section(2)

• Similar full-cycle capital efficiency(2)

Emerging resource expansion across all Nest regions

Illustration not to scale

1) 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.2) Assumes 3 lower Montney locations are developed in tandem with the company’s standard 6-well upper/middle Montney development profile



CURRENT HEDGE POSITIONSAs at June 30, 2020

1) Gas hedges are a mix of HH swaps and collars, Chicago FP swaps and AECO FP swaps2) 2020 FX Hedges include FX component of CAD WTI hedges



SELECTED FINANCIAL & OPERATIONAL INFORMATION

1) See "Note Regarding Product Types" in the Important Notice.2) Starting in 2018, 7G began presenting C5+ in the NGL mix as a condensate volume (previously reported as an NGL volume). 3) Excludes the purchase and resale of liquids and natural gas in respect of transportation commitment optimization and marketing activities. Refer to the Q2 2020 MD&A as filed on SEDAR for additional information.4) Refer to the "Important Notice" section at the end of this presentation for additional information regarding the Company's non-GAAP and additional GAAP measures. 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.


VII - Recent Quarterly ResultsOPERATING RESULTS Q2 2020 Q1 2020 Q4 2019 Q3 2019 Q2 2019 Q1 2019 Q4 2018 Q3 2018 Q2 2018 Q1 2018 YE 2019 YE 2018

Average daily production (1)

Condensate (2) (mbbl/d) 64.3 69.0 75.0 75.5 75.9 72.7 81.8 87.3 69.0 67.3 74.8 76.4

Natural gas (MMcf/d) 467.9 489.1 523.1 515.3 489.6 483.6 515.4 511.3 461.3 473.3 503.0 490.5

Other NGLs (2) (mbbl/d) 40.9 43.0 45.9 43.2 44.3 44.1 47.4 47.3 41.2 41.5 44.4 44.4

Total (mboe/d) 183.2 193.5 208.1 204.6 201.8 197.4 215.1 219.8 187.1 187.7 203.0 202.6

CGR Ratio 137 141 143 147 155 150 155 175 150 142 149 156

LGR Ratio 87 88 88 84 90 91 92 93 89 88 88 91

Realized Prices

Condensate (2) ($/bbl) 26.59 56.84 66.39 65.59 71.91 63.00 53.57 79.26 81.67 73.39 66.76 71.63

Natural gas ($/Mcf) 2.49 2.65 3.25 2.85 3.29 4.32 4.77 3.65 3.79 3.54 3.41 3.98

Other NGLs (2) ($/bbl) 12.01 8.84 10.75 2.74 4.19 7.46 8.44 14.02 13.39 13.33 6.34 12.21

18.38 28.93 34.48 31.97 35.95 35.44 33.66 42.99 42.42 38.19 34.44 39.33

Netbacks (4)

Liquids and natural gas sales ($/boe) 18.38 28.93 34.48 31.97 35.95 35.44 33.66 42.99 42.42 38.19 34.44 39.33

Royalties ($/boe) (0.97) (2.29) (2.62) (1.99) (2.19) (2.30) (0.99) (2.20) (0.96) (1.12) (2.28) (1.34)

Operating expense ($/boe) (4.16) (4.54) (4.43) (4.81) (5.00) (4.93) (5.25) (5.22) (6.00) (5.73) (4.79) (5.52)

Transportation, processing and other expense ($/boe) (7.53) (7.03) (7.01) (6.46) (6.64) (6.65) (7.07) (6.14) (6.93) (6.24) (6.69) (6.65)

Operating netback before the following (4) ($/boe) 5.72 15.07 20.42 18.71 22.12 21.56 20.35 29.43 28.53 25.10 20.68 25.82

Realized hedging gain (loss) ($/boe) 6.44 3.54 0.55 1.63 0.04 (0.34) (1.58) (1.79) (1.04) (0.78) 0.48 (1.33)

Marketing Income (loss) (4)(5) ($/boe) (0.80) (0.45) 0.18 0.19 0.07 0.77 0.20 0.28 0.53 0.62 0.30 0.39

Operating netback (4) ($/boe) 11.36 18.16 21.15 20.53 22.23 21.99 18.97 27.92 28.02 24.94 21.46 24.88

General and administrative expense ($/boe) (0.89) (1.01) (0.83) (0.84) (0.85) (0.94) (0.91) (0.66) (0.82) (0.65) (0.86) (0.76)

Finance expense and other ($/boe) (2.14) (1.53) (1.87) (1.60) (2.03) (1.98) (1.07) (1.42) (1.71) (1.83) (1.87) (1.51)

Funds flow per boe (4) ($/boe) 8.33 15.62 18.45 18.09 19.35 19.07 16.99 25.84 25.49 22.46 18.73 22.61

FINANCIAL RESULTS (4)

Condensate (2) ($MM) 155.6 356.9 458.1 455.6 496.7 412.2 403.2 636.6 512.8 444.5 1,822.6 1,997.3

Natural gas ($MM) 106.2 118.0 156.6 135.3 146.6 187.9 225.7 171.8 159.2 156.1 626.4 712.6

Other NGLs (2) ($MM) 44.7 34.6 45.4 10.9 16.9 29.6 36.8 61.0 50.2 49.8 102.8 197.8

Liquids and natural gas sales (3) ($MM) 306.5 509.5 660.1 601.8 660.2 629.7 665.7 869.4 722.2 650.4 2,551.8 2,907.7

Royalties ($MM) (16.1) (40.3) (50.2) (37.5) (40.2) (40.9) (19.5) (44.4) (16.4) (18.9) (168.8) (99.2)

Operating expense ($MM) (69.4) (80.0) (84.9) (90.6) (91.8) (87.5) (103.8) (105.5) (102.2) (96.8) (354.8) (408.3)

Transportation, processing and other expense ($MM) (125.6) (123.8) (134.3) (121.6) (121.9) (118.1) (139.9) (124.2) (118.0) (109.7) (495.9) (491.8)

Operating netback before the following (4) ($MM) 95.4 265.4 390.7 352.1 406.3 383.2 402.5 595.3 485.6 425.0 1,532.3 1,908.4

Realized hedging gain (loss) ($MM) 107.3 62.4 10.5 30.6 0.8 (6.0) (31.2) (36.2) (17.7) (13.1) 35.9 (98.2)

Marketing Income (loss) (4)(5) ($MM) (13.4) (8.0) 3.4 3.6 1.3 13.6 3.9 5.7 9.1 10.0 21.9 28.7

Operating netback (4) ($MM) 189.3 319.8 404.6 386.3 408.4 390.8 375.2 564.8 477.0 421.9 1,590.1 1,838.9

Revenue (6) ($MM) 306.0 989.4 669.6 718.0 795.5 546.3 1,146.8 809.0 560.4 653.7 2,729.4 3,169.9

Funds flow (4) ($MM) 138.8 275.0 353.2 340.5 355.3 338.8 336.2 522.5 434.0 379.5 1,387.8 1,672.2

Net Income (loss) ($MM) (116.9) (1,009.2) 82.6 85.1 295.3 10.8 245.4 196.4 (24.6) 22.7 473.8 439.9

Adjusted net income (loss) ($MM) (43.1) 34.0 89.7 78.5 96.8 84.0 66.3 208.3 169.6 129.4 349.0 573.6

Free cash flow (deficit) (4) ($MM) 69.4 9.2 120.3 55.9 44.2 (62.1) 73.9 164.3 (128.6) (203.1) 158.3 (93.5)

Capital investments

Drilling and completions ($MM) 15.9 162.6 132.5 171.0 172.9 231.4 148.9 232.6 335.9 319.6 707.8 1,037.0

Facilities and infrastructure ($MM) 38.9 82.2 59.0 76.9 119.5 132.2 67.7 90.8 179.3 207.0 387.6 544.8

Land and other ($MM) 14.6 21.0 41.4 36.7 18.7 37.3 45.7 34.8 47.4 56.0 134.1 183.9

Total capital investments ($MM) 69.4 265.8 232.9 284.6 311.1 400.9 262.3 358.2 562.6 582.6 1,229.5 1,765.7


IMPORTANT NOTICEGeneral AdvisoryThe information contained in this presentation does not purport to be all-inclusive or contain all information that readers may require. Prospective investorsare encouraged to conduct their own analysis and review of Seven Generations Energy Ltd. (“Seven Generations”, “Seven Generations Energy”, “7G”, “VII”, the“company” or the “Company”) and of the information contained in this presentation. Without limitation, prospective investors should read the record ofpublicly filed documents relating to the Company, consider the advice of their financial, legal, accounting, tax and other professional advisors and suchother factors they consider appropriate in investigating and analyzing the Company. An investor should rely only on the information provided by theCompany and is not entitled to rely on parts of that information to the exclusion of others. The Company has not authorized anyone to provide investorswith additional or different information, and any such information, including statements in the media 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 dilutedbasis.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-richnatural gas sector of the oil and natural gas industry, and certain other risks that are associated with Seven Generations’ stage of development. Aninvestment 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 canafford to lose some or all of their investment.

Non-GAAP Measures AdvisoryIn addition to using financial measures prescribed by International Financial Reporting Standards (“IFRS”), references are made in this presentation tocertain terms or performance measures commonly used in the oil and natural gas industry that are not defined under IFRS, including “enterprise value”,“adjusted net income”, “adjusted net income per diluted share”, “marketing income”, “marketing income per boe”, “operating netback”, “operating netbackbefore realized hedging gains and marketing income”, “funds flow per boe”, “free cash flow” and “capital efficiency”.

The data presented is intended to provide additional information and should not be considered in isolation or as a substitute for measures of performanceprepared in accordance with IFRS. Such non-GAAP measures should be read in conjunction with the company’s consolidated financial statements for theyears ended December 31, 2019 and 2018 and the accompanying notes and Non-GAAP measures in Management’s Discussion and Analysis dated July 28,2020, for the three and six months ended June 30, 2020 and 2019. Readers are cautioned that the non-GAAP measures do not have any standardizedmeaning and should not be used to make comparisons between the company and other companies without also taking into account any differences inthe way the calculations were prepared. For additional information about Non-GAAP measures, please see “Advisories and Guidance – Non-GAAP financialmeasures” in Management’s Discussion and Analysis February 26, 2020, for the years ended December 31, 2019 and 2018 and the condensed interimconsolidated financial statements for the three and six months ended June 30, 2020 and 2019.

“Operating netback before realized hedging gains and marketing income” is calculated on a per boe basis and is determined by deducting royalties,operating, transportation, processing and other expenses from oil and natural gas sales, before taking into account marketing income and excludingrealized hedging gains or losses. For the year ended December 31, 2019, operating netback before realized hedging gains and marketing income wascalculated by subtracting royalties of $2.28, operating expenses of $4.79 and transportation, processing and other costs of $6.69, from revenues per boe of$34.44. Operating netback before realized hedging gains and marketing income is utilized by Seven Generations and others to assess the profitability of theCompany's liquids and natural gas assets at the field level and to compare results to prior periods by isolating for the impact of changes in productionvolumes.

“Adjusted net income” is defined as “net income, excluding unrealized gains and losses on financial instruments, realized foreign exchange gains and losseson debt repayments, deferred income tax impacts from changes in tax rates, accrued redemption premiums on senior notes, gains and losses ondisposition of assets, transaction costs, net losses on investments in associates and the respective income tax impact of those adjustments”. Adjusted netincome per diluted share reflects adjusted net income on a per share basis, which is calculated by dividing adjusted net income by the Company'sweighted average shares outstanding and the dilutive effect of outstanding equity compensation units during the period. Adjusted net income is used bySeven Generations and others as a performance measure that provides comparability of financial results between periods by excluding highly variable andnon-operating related items such as unrealized gains or losses on financial instruments.

“Enterprise value” is calculated as the market capitalization of the company plus net debt, where market capitalization is defined as the total number ofshares outstanding multiplied by the price per share at a given point in time. “Net debt” is calculated as current and non-current portions of seniorunsecured notes, plus adjusted working capital deficiency (surplus) and long-term lease liabilities. Enterprise value differs from total capitalization, asdefined in the additional GAAP measures in the MD&A, because of the usage of market value of equity, as opposed to the book value of equity.

“Capital Efficiency” is calculated by dividing total anticipated drill, complete, equip and tie-in costs (DCET) by the anticipated IP365 production rateexpressed in boe/d. The measure is considered to be useful for investors and management because it describes the magnitude of capital investment

required to add production over the course of a year from each of the company’s core operating regions.

“Net debt”, “Adjusted EBITDA” and “total capitalization” have been included in Note 15 - Capital Management in the company’s consolidated financialstatements for the years ended December 31, 2019 and 2018 and funds flow has been presented in the consolidated cash flow statement. Accordingly,these performance measures are additional GAAP measures and are not considered non-GAAP measures. Readers are cautioned that these additionalGAAP measures do not have any standardized meaning and should not be used to make comparisons between Seven Generations and other companieswithout also taking into account any differences in the methods by which the calculations are prepared. For additional information about these measures,please see “Advisories and Guidance – Additional GAAP measures” in Management’s Discussion and Analysis February 26, 2020, for the years endedDecember 31, 2019 and 2018 and "Advisories and Guidance - GAAP measures" in Management's Discussion and Analysis dated July 28, 2020, for the threeand six months ended June 30, 2020 and 2019.

Forward-Looking Information AdvisoryThis presentation contains certain forward-looking information and statements that involve various risks, uncertainties and other factors. The use of any ofthe words “anticipate”, “continue”, “estimate”, “expect”, “may”, “will”, “should”, “believe”, “plans”, “outlook”, “forecast” and similar expressions are intended toidentify forward-looking information or statements. In particular, but without limiting the foregoing, this presentation contains forward-looking informationand statements pertaining to the following: the company’s strategies, strategic pursuits, priorities, goals, strategic objectives and competitive strengths,including its focus on responsible development, innovation, continual improvement, improved capital and operating efficiencies, value creation and freecash flow generation; expected drilling inventory/drilling locations/potential drilling opportunities; inventory life; expected number of years to developdrilling inventory/potential drilling opportunities; upside potential of the company’s properties; details and forecasts related to the 2020 budget, includingthose contained on the slide titled “2020 Budget Details”, and among them: expected production, expected total capital investments in 2020, the numberof development wells to be brought on-stream, natural gas, condensate and NGL yields, royalty rates, operating expenses, transportation expenses, G&A andinterest expenses; forecast drilling and completion costs; forecast funds flow sensitivity; free cash flow potential; forecast condensate supply and demand;the percentage of 2020 condensate and natural gas production that has been hedged; the forecast revenue mix for 2020; the productivity anddeliverability of various current and future development areas; transportation and processing capacity; forecast net debt to trailing 12-month adjustedEBITDA at different commodity price scenarios; forecast full-cycle and single well economics, capital efficiency, condensate production, CGRs, IRRs, NPVsand PIRs; the expectation that full-cycle capital efficiencies will be similar in the Lower Montney formation as they are in the upper/middle Montneyformations; expectation that the area recently added to Nest 2 will have sweet, liquids rich condensate production and will be analogous (in terms ofproduction) to locations in North-West Nest 2; hedge targets; objectives of hedging program; access to sales points; expected future sales points; potentialto expand the boundary of the Nest 3 area; potential to expand the inventory per section and forecast NPV per section with the potential addition of LowerMontney locations; delineation potential and planned delineation; and the references to development area forecasts and type-curve estimates. In addition,information and statements in this presentation relating to reserves, related future development costs, related net present value of future net revenue andcontingent resources are deemed to be forward-looking statements as they involve the implied assessment, based on certain estimates and assumptionsthat the reserves and/or 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, NGLsand natural gas prices being consistent with current commodity price forecasts after factoring in quality adjustments at the company’s points of sale; thecompany’s continued ability to obtain qualified staff and equipment in a timely and cost-efficient manner; third party transportation and processingfacilities will be operated in an efficient and reliable manner; drilling and completions techniques and infrastructure and facility design concepts that havebeen successfully applied by the Company elsewhere in its Kakwa River Project may be successfully applied to other properties; that wells drilled in thesame 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 futurewells 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 forthose areas; the consistency of the current regulatory regime and legal framework, including the laws and regulations governing the company’s oil and gasoperations, royalties, taxes and environmental matters in the jurisdictions in which the Company conducts its business and any other jurisdictions in whichthe Company may conduct its business in the future; the company’s ability to market production of oil, NGLs and natural gas successfully to customers; thatthe company’s future production levels, amount of future investment, costs, royalties, unabsorbed demand charges, facilities downtime and developmenttiming will be consistent with the company’s current development plans and budget; the pace of development will be consistent with the company’scurrent plans; the applicability of new technologies for recovery and production of the company’s reserves and resources may improve capital andoperational efficiencies in the future; the recoverability of the company’s reserves and resources; sustained future capital investment by the company; futurecash flows from production; the Company’s future sources of funding; the Company’s future debt levels; geological and engineering estimates in respect ofthe Company’s reserves and resources; the geography of the areas in which the Company is conducting exploration and development activities, and theaccess, economic, regulatory and physical limitations to which the Company may be subject from time to time; the impact of competition on theCompany; and the Company’s ability to obtain financing on acceptable terms.


IMPORTANT NOTICEExcept where otherwise indicated, the funds flow, free cash flow and adjusted EBITDA forecasts referenced in this presentation were calculated basedupon the assumptions outlined on the slide titled “2020 Budget Details” and price assumptions based on first quarter 2020 actual price realizations andstrip pricing for the balance of the year as at April 25, 2020, which for the full year averages approximately US$29.00/bbl WTI, US$2.00/MMbtu NYMEX/HHand 0.72 USD/CAD FX. NGLs as % of WTI: C3 26%, C4 30%, C5 – $8 USD/bbl differential. AECO Basis US$0.50/MMbtu. Operating cost assumptions reflectrecent actual cost trends with adjustments to address planned activity levels. Royalty rate assumptions were calculated 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&Acost assumptions reflect recent actuals and expectations for a staff count and information technology investments in 2020.

Net debt forecasts were calculated by adding the principal of the unsecured notes to the forecasted principal of the Company’s credit facility, less forecastadjusted net working capital.

Assumptions made in the calculations of forecasted economics, including forecasted NPVs, IRRs, price sensitivities, commodity prices and recovery factorsreflect cost assumptions that are based upon recent actual cost trends with adjustments to address planned activity levels. Royalty rates were calculatedusing a price of US$40/bbl, net of credits as of Dec.31/19 and projected C* for new wells drilled or to be drilled in 2020. Royalty rates were calculated net ofexpected gas cost allowance investments in gas plants. G&A costs used in the forecasts reflect recent actuals.

An assumption has also been made that further well delineation activities will confirm management’s estimates regarding reservoir quality of its propertiesthat fall outside of the Company’s core development areas. With respect to the estimated number of drilling locations or potential drilling opportunitiesthat are referenced herein, various assumptions have been made. These assumptions are described under the heading “Note Regarding Potential DrillingOpportunities” 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 riskfactors that are set forth in the annual information form dated February 26, 2020 for the year ended December 31, 2019 (the “AIF”), and Management'sDiscussion and Analysis dated July 28, 2020, for the three and six months ended June 30, 2020 and 2019, which are available on the SEDAR website atwww.sedar.com, 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; global or national health concerns, including the outbreak of pandemic or contagious diseases, suchas the current novel coronavirus; recent and ongoing declines in general economic, business or industry conditions and weakness and volatility in themarket conditions for the oil and gas industry; civil unrest, pandemics and other disruptions and dislocations; the potential for future impairment losses;variance of the Company’s actual capital costs, operating costs and economic returns from those anticipated; the ability to find, develop or acquireadditional reserves and the availability of the capital or financing necessary to do so on satisfactory terms; risks related to the exploration, development andproduction of oil and natural gas reserves and resources; negative public perception of oil sands development, oil and natural gas development andtransportation, hydraulic fracturing and fossil fuels; actions by governmental authorities, including changes in government regulation, royalties and taxation;political changes; 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 successfullyintegrate future acquisitions or businesses; the availability, cost or shortage of rigs, equipment, raw materials, supplies or qualified personnel; the adoptionor modification of climate change legislation by governments; potential impacts of climate change on the Company’s operations; uncertainty associatedwith estimates of oil, NGLs and natural gas reserves and resources and the variance of such estimates from actual future production; dependence uponcompressors, gathering lines, pipelines and other facilities, certain of which the Company does not control; the ability to satisfy obligations under theCompany’s firm commitment transportation and processing arrangements; the export and sale of natural gas to the United States; the uncertainties relatedto the Company’s identified drilling locations; the high-risk nature of successfully stimulating well productivity and drilling for and producing oil, NGLs andnatural gas; operating hazards and uninsured risks; the risks of fires, floods and natural disasters, which could become more frequent or of a greatermagnitude as a result of climate change; the possibility that the Company’s drilling activities may encounter sour gas; execution risks associated with theCompany’s business plan; failure to acquire or develop replacement reserves; the concentration of the Company’s assets in the Kakwa area; unforeseen titledefects; Indigenous claims; failure to accurately estimate abandonment and reclamation costs; development and exploratory drilling efforts and welloperations may not be profitable or achieve the targeted return; horizontal drilling and completion technique risks and failure of drilling results to meetexpectations 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 thenear future; failure to realize the anticipated benefits of acquisitions or dispositions; failure of properties acquired now or in the future to produce asprojected and inability to determine reserve and resource potential, identify liabilities associated with acquired properties or obtain protection from sellersagainst 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 Canadian oil and gasindustry; alternatives to and changing demand for petroleum products; extensive competition in the Company’s industry; changes in the Company’s creditratings; 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; terroristattacks or armed conflict; cyber security risks, loss of information and computer systems; inability to dispose of non-strategic assets on attractive terms; thepotential for security deposits to be required under provincial liability management programs; reassessment by taxing and royalty authorities of theCompany’s prior transactions and filings; variations in foreign exchange rates and interest rates; risks associated with counterparties in risk managementactivities related to commodity prices and foreign exchange rates; sufficiency of insurance policies; potential for litigation; variation in future calculations ofnon-IFRS measures; breach of and potential enforceability issues in contracts; impact of expansion into new activities on risk exposure; inability of theCompany to respond quickly to competitive pressures; and the risks related to the common shares that are publicly traded and the Company’s senior notesand other indebtedness.

Any financial outlook and future-oriented financial information contained in this document regarding prospective financial performance, financial positionor cash flows is based on assumptions about future events, including economic conditions and proposed courses of action based on management’sassessment of the relevant information that is currently available. Projected operational information contains forward-looking information and is based on anumber of material assumptions and factors, as are set out above. These projections may also be considered to contain future oriented financialinformation or a financial outlook. The actual results of the Company’s operations for any period will likely vary from the amounts set forth in theseprojections and such variations may be material. Actual results will vary from projected results. Readers are cautioned that any such financial outlook andfuture-oriented financial information contained herein should not be used for purposes other than those for which it is disclosed herein. The forward-looking information and statements contained in this document speak only as of the date hereof and the Company does not assume any obligation topublicly update or revise them to reflect new events or circumstances, except as may be required pursuant to applicable laws.

Presentation of Oil and Gas InformationEstimates of the Company’s reserves, the net present value of future net revenue attributable to the company’s reserves and the Company’s contingentresources that are contained herein are based upon reports prepared by McDaniel & Associates Consultants Ltd. (“McDaniel”), the Company’s independentqualified reserves evaluator, as at December 31, 2019 (the “McDaniel Reports”). The estimates of reserves and contingent resources provided in thispresentation are estimates only and there is no guarantee that the estimated reserves and contingent resources will be recovered. Actual reserves andcontingent resources may be greater than or less than the estimates provided in this in this presentation and the differences may be material. There is noassurance that the forecast price and cost assumptions applied by McDaniel in evaluating Seven Generations’ reserves and contingent resources will beattained and variances could be material. There is uncertainty that it will be commercially viable to produce any part of the contingent resources.

This presentation includes estimates of contingent resources, as at December 31, 2019, that have been risked by McDaniel for the probability of loss orfailure in accordance with the COGE Handbook. For contingent resources, the risk component relating to the likelihood that an accumulation will becommercially developed is referred to as the chance of development. Contingent resources in the “development pending” project maturity subclass havebeen assigned by McDaniel, as at December 31, 2019, 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 Project. The COGE Handbook indicates that it is appropriate to categorize contingent resources in thedevelopment pending project maturity subclass where resolution of the final conditions for development are being actively pursued and there is a highchance of development. Approximately 98% of the contingent resources attributed to the Company’s properties by McDaniel, as at December 31, 2019,have been classified as “development pending” and the balance of the contingent resources have been classified as “development unclarified”. The primarycontingency for “development pending” contingent resources is that the Company’s current timeframe for development falls outside of the developmenthorizon permitted by the COGE Handbook for booking undeveloped reserves. If the Company’s development plans were to change to accelerate the paceof development, then contingent resources may be converted to undeveloped reserves once sufficient processing capacity has been secured for theincremental volumes and plans are in place to develop the resources within the timeframe permitted for undeveloped reserves. Contingent resources inthe “development unclarified” project maturity subclass have been assigned by McDaniel, as at December 31, 2019, in the Wilrich formation within theCretaceous stack across the Project area. The COGE Handbook indicates that it is appropriate to categorize contingent resources in the “developmentunclarified” project maturity subclass when the evaluation is incomplete and there is ongoing activity to resolve any risks or uncertainties. These resourceestimates are not classified as reserves at this time, pending further reservoir delineation, project application, facility and reservoir design work.

The reserves and contingent resources estimates contained in this presentation should be reviewed in connection with the AIFs which are available on theSEDAR website at www.sedar.com, and contain important additional information regarding the independent reserves and contingent resource evaluationsthat were conducted by McDaniel, as presented in the McDaniel Reports, and a description of, and important information about, the reserves and resourcesterms used in this presentation.


IMPORTANT NOTICENote Regarding Oil and Gas MetricsUnless otherwise specified, all production is reported on the basis of the company’s working interest (operating and non-operating) before the deduction ofroyalties payable. Seven Generations has adopted the standard of 6 Mcf:1 bbl when converting natural gas to boes. Condensate and other NGLs areconverted 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 onan 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: 1bbl 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 ofvalue.

Note Regarding Industry MetricsThis presentation includes certain industry metrics, including GHGe or CO2e, which do not have standardized meanings or standard methods ofcalculation and therefore such measures may not be comparable to similar measures used by other companies and should not be used to makecomparisons. 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 of the future performance of the Company and future performance may not compare to the performance inprevious periods.

The GHGe or CO2e estimates for 7G provided herein were third-party quantified and verified. For the 2019 reporting year, based on 2018 performance, 7G’scarbon intensity was calculated to be 0.0144 tonnes of CO2e per boe. 7G quantified and reported its GHG emissions using the “operational control”approach. 7G’s deemed organizational boundary included its corporate offices and all natural gas (and associated hydrocarbon liquids) extraction andprocessing facilities (including well pads). 7G elected to report its Scope 1 and 2 GHG emissions and not to report its Scope 3 GHG emissions. For thepurposes of 7G’s GHG emissions reporting:

• Scope 1 emissions were defined as direct emissions from GHG sources that 7G owned or controlled (including, but not limited to, emissions fromstationary equipment, flaring, mobile combustion, fugitive emissions and venting emissions). Scope 1 emissions quantification was informed by 7G’scomprehensive LDAR program.

• Scope 2 emissions were defined as indirect GHG emissions that resulted from 7G’s consumption of energy in the form of purchased electricity; and• 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.

7G’s drilling and completion activities in the relevant periods were conducted by third parties as were certain gas processing operations at the Pembina 8-13 Kakwa River Plant; consequently, those activities were deemed to be Scope 3.

7G retained Brightspot Climate Inc. to support the quantification of GHG emissions. Emissions for all facilities were quantified in accordance with themethodologies specified in Alberta’s Carbon Competitiveness Incentive Regulation (“CCIR”) and Specified Gas Reporting Regulation, and Environment andClimate Change Canada’s Greenhouse Gas Emissions Reporting Program, as applicable. Measured quantities, such as fuel volume, fuel carbon content, flarevolumes, venting volumes, fugitive volumes, and electricity consumption were used, where metered data was available. Emission factors from publishedgovernment sources were applied to the calculations. Third party verification was conducted by Millennium EMS Solutions. This verification was completedin accordance with the ISO 14064:3 standard and the requirements of CCIR.

Note Regarding Product TypesThis news release includes references to total average daily production, condensate production, other NGL production, natural gas production, liquidsproduction, LGRs and CGRs. Other NGLs refers to all natural gas liquids, except for condensate, which is reported separately. Natural gas refers toconventional natural gas and shale gas combined. Liquids refers to condensate and other NGLs combined. LGR refers to the ratio of oil, condensate andother NGL production (combined), in relation to natural gas production. CGR refers to the ratio of condensate production, in relation to natural gasproduction. The following table is intended to provide supplemental information about the product type composition for each of the production figuresthat are provided in this presentation:

This presentation also makes reference to Company's forecasted total average daily production of 175 – 185 mboe/d for 2020. Seven Generations expectsthat approximately 32% - 36% of that production will be comprised of condensate, 39% - 41% will be comprised of shale gas, 22% - 24% will be comprisedof other NGLs and 3% will be comprised of conventional natural gas.

Note Regarding Development Area Forecast Economics and Type-CurvesType-curves were used to develop the development area forecast economics shown in this presentation. The type-curves were prepared by internalqualified reserves evaluators from 7G. For each of the type-curves, wells with significant deviation in completions technique, or that had mechanical issuesor parent-child interactions between wells, were excluded from the analysis to avoid perceived outlier effects. Non-producing days were removed from theproducing time plotted in the type-curves. When type-curves are used for budgeting purposes, facility constraints, parent-child well interactions,mechanical issues, expected downtime for concurrent operations, facility outages and gas processing shrink adjustment factors are then accounted for, butthose assumptions and adjustments are not reflected in the type-curves themselves or in the forecast economics that have been provided in thispresentation. All data reflected in the type-curves is raw wellhead data. Condensate rates have been adjusted downwards in the type-curves to account forassumed shrinkage due to entrainment of NGLs in the wellhead separator liquid, as directly measured. This correction is the result of an empirical equationbased 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 tovolumetric estimates attributable to properties in the Company’s Nest 1, Nest 2 and Nest 3 areas, respectively, based upon the Company’s understanding ofthe geology and reservoir parameters at the time the type curves were developed. Early-life statistics use data from the Nest 1, Nest 2 and Nest 3 producingwells

Condensate

(mbbl/d)

Other NGLs

(mbbl/d)

Shale gas

(MMcf/d)

Conventional

natural gas

(MMcf/d)

Total (mboe/d)

Three months endedMarch 31, 2018 67.3 41.5 425.4 47.9 187.7June 30, 2018 69.0 41.2 428.8 32.5 187.1September 30, 2018 87.3 47.3 479.8 31.5 219.8December 31, 2018 81.8 47.4 480.9 34.5 215.1March 31, 2019 72.7 44.1 447.3 36.3 197.4June 30, 2019 75.9 44.3 455.6 34.0 201.8September 30, 2019 75.5 43.2 480.5 34.8 204.6December 31, 2019 75.0 45.9 492.4 30.7 208.1March 31, 2020 69.0 43.0 461.5 27.6 193.5June 30, 2020 64.3 40.9 441.0 26.9 183.2

Year endedDecember 31, 2018 76.4 44.4 454.0 36.5 202.6December 31, 2019 74.8 44.4 469.1 33.9 203.0


IMPORTANT NOTICEThe Nest 1 type-curve referenced is based upon production data from 26 wells in the upper/middle Montney formation on production between 2017-2019that are considered to be reflective of expected future performance, excluding effects from parent-child well interactions, unusually tight spacing, facilityconstraints, downtime and mechanical failures. Type-curves are meant to be representative of go-forward completion designs utilizing slickwater fracs withproppant intensities of 1.8 – 2.2 T/m.

The Nest 2 type-curve referenced is based upon production data from 101 wells in the upper/middle Montney formation on production between 2017-2019that are considered to be reflective of expected future performance, excluding effects from parent-child well interactions, unusually tight spacing, facilityconstraints, downtime and mechanical failures. Type-curves are meant to be representative of go-forward completion designs utilizing slickwater fracs withproppant intensities of 1.8 – 2.2 T/m.

The Nest 3 type-curve referenced is based upon production data from 4 wells in the upper/middle Montney formation on production in 2017 that areconsidered to be reflective of expected future performance, excluding effects from parent-child well interactions, unusually tight spacing, facilityconstraints, downtime and mechanical failures. Type-curves are meant to be representative of go-forward completion designs utilizing slickwater fracs withproppant intensities of 1.8 – 2.2 T/m.

The Company has opted to rely upon the type-curve forecasts that have been prepared by internal reservoir engineers from 7G in this presentation, ratherthan the type-curves prepared by McDaniel, because the internally generated type-curves are what the Company has used for capital budgeting andcorporate 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 othercompanies. Actual results may vary significantly from the Company’s forecasts and estimates.

The Company’s oil, natural gas and NGL reserves and contingent resources, as at December 31, 2019, 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 contingentresources to approximately 28% of the Nest 1 sections evaluated; proved plus probable reserves to approximately 84% of the Nest 2 sections evaluated; bestestimate contingent resources to approximately 16% of the Nest 2 sections evaluated; proved plus probable reserves to approximately 85% of the Nest 3sections evaluated; best estimate contingent resources to approximately 15% of the Nest 3 sections evaluated; proved plus probable reserves toapproximately 0% of the Wapiti sections evaluated; and best estimate contingent resources to approximately 100% of the Wapiti sections evaluated.

On the slide titled “Economics and Inventory”, the same pricing assumptions were used to develop the economic forecasts as in the 2020 budget. Realizedgas pricing for single well economics is based on a blend of Dawn/Malin and AECO markets. Variable gas and liquids opex were assumed at C$5.00/bbland C$0.60/mcf, respectively. Fixed well operating costs were assumed at $20,000/mo. NGL recoveries and shrinkage factors reflected in the analysis arebased 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 wellas 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 andAux Sable, which depends upon an assumed heating value and has been assumed to extend for the entire productive life of the wells.

The forecast half-cycle economics include only the cost to drill, complete, equip and tie-in wells. The forecasts do not take into account certain other coststhat would be required to construct infrastructure, including Super Pads, central processing facilities, regional gathering facilities, condensate stabilizationfacilities and other infrastructure, nor do they take into account land acquisition costs, corporate overhead (G&A) expenses, financing costs or corporatetaxes. Such forecast economics are intended to represent the marginal return of a single well investment on an existing Super Pad. The forecasts present anidealistic view of results that could be achieved in the absence of additional infrastructure costs, operational challenges or downtime.

Full-cycle economics are intended to represent a development scenario including adjustments for downtime and facility constraints, additionalinfrastructure costs and corporate overhead (G&A). Actual results will differ from the forecasts for the reasons described above and because of the risks andrisk 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 OpportunitiesThe references to drilling locations or potential drilling opportunities that are contained herein are based upon the McDaniel Reports, as at December 31,2019. Some of the locations have already been drilled as part of the Company’s 2020 development program.

Of the 538 potential drilling locations or drilling opportunities that were estimated to be contained within the company’s Nest 1 area, as at December 31,2019, 72% were attributed proved plus probable reserves and 28% were attributed best estimate contingent resources in the McDaniel Reports.

Of the 620 potential drilling locations or drilling opportunities that were estimated to be contained within in the company’s Nest 2 area, as at December 31,2019, 73% were attributed proved plus probable reserves and 27% were attributed best estimate contingent resources in the McDaniel Reports.

Of the 158 potential drilling locations or drilling opportunities that were estimated to be contained within in the company’s Nest 3 area, as at December 31,2019, 81% were attributed proved plus probable reserves, and 19% were attributed best estimate contingent resources in the McDaniel Reports.

For the purposes of estimating potential drilling locations or drilling opportunities, McDaniel has assumed well spacing of 12 wells per section and a lateralwell lengths of 2,460 metres based upon industry practice and internal review. The anticipated well spacing and lateral well length is expected to changeover time as technology and the McDaniel’s understanding of the reservoir changes. For the purposes of the estimates, the Company has assumed thatnatural gas production will be delivered into the Alliance Pipeline or NGTL system and that liquids will be extracted at the Pembina Kakwa River plant, at7G’s wholly-owned plants in Alberta and at Aux Sable’s facilities near Chicago, Illinois.

The number of future drilling opportunities described for the “Lower Montney”, “Wapiti”, “Rich Gas” and “Cretaceous” areas on the slide titled “Economicsand Inventory” represents the number of locations estimated to be attributed to those areas by McDaniel in the McDaniel Reports.

There is no certainty that the company will drill any of the identified drilling opportunities or drilling locations and there is no certainty that such locationswill result in additional reserves, resources or production. The drilling locations on which the company will actually drill wells, including the number andtiming thereof, will be dependent upon the availability of funding, regulatory approvals, seasonal restrictions, oil and natural gas prices, costs, actual drillingresults, additional reservoir information that is obtained, and other factors. While certain of the estimated undeveloped 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 managementhas 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 orproduction.

The competitor flow test and initial production history shown on the slide titled “Nest 1” has been obtained by 7G from public sources as at year-end 2018.The 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 inaccordance with applicable regulatory requirements. All of the competitor wells referenced were drilled in the Montney formation. The information isconsidered to be relevant because the geology of properties owned by 7G are considered to be similar to the competitor properties that are referenced.Significant production or pressure decline was noted in the data for the flowtests and/or early production history, and pressure transient analysis and welltest interpretation had not yet been carried out at the time the data was posted. As such, the information should be considered to be preliminary untilfurther 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 resultshave been obtained during a 60 day initial flow period (includes completions flowback and flow through permanent facilities). The average gas productionrate observed was 3,136 Mcf/d and the average condensate production rate observed was 1,375 bbl/d. Cumulative gas production was 188 MMcf, cumulativecondensate production was 82,505 bbls and cumulative produced water was 59,082 bbls. Gas, condensate, and water rates ramped up over a period of 12days. Gas maintained a plateau rate of about 4,100 Mcf/d) while condensate gradually declined as expected. Tubing pressure reached a maximum of 9,300KPa (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 750bbl/MMcf. Pressure transient analysis and well test interpretation has not yet been conducted for this well.

The initial and/or early production rates described in this presentation are not necessarily indicative of longer-term performance or ultimate recovery.


IMPORTANT NOTICEOil 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 thequantity that will actually be recovered. It is equally likely that the actual quantities recovered will be greater or less than the best estimate. Resources in thebest estimate case have a 50% probability that 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 usingestablished technology or technology under development, but which are not currently considered to be commercially recoverable due to one or morecontingencies. Contingencies may include factors such as economic, environmental, social, political factors and regulatory matters, a lack of markets or aprolonged timetable for development. It is also appropriate to classify as contingent resources the estimated discovered recoverable quantities associatedwith a project in the early evaluation stage.

“developed producing reserves” are those gross reserves that are expected to be recovered from completion intervals open at the time of the estimate.These reserves may be currently producing or, if shut in, they must have previously been on production, and the date of resumption of production must beknown with reasonable certainty.

“developed reserves” are those gross reserves that are expected to be recovered from existing wells and installed facilities or, if facilities have not beeninstalled, that would involve a low expenditure (for example, when compared to the cost of drilling a well) to put the reserves on production. The developedcategory may be subdivided into producing and non-producing.

“gross” means: (i) in relation to the Company’s interest in production, reserves or contingent resources, its “company gross” production, reserves orcontingent resources, which are the Company’s working interest (operating or non-operating) share before deduction of royalties and without including anyroyalty 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, thetotal area of properties in which the Company has an interest.

“liquids” refers to oil, condensate and other NGLs.

“probable reserves” are those additional reserves that are less certain to be recovered than proved reserves. It is equally likely that the actual remainingquantities recovered will be greater or less than the sum of the estimated proved plus probable reserves.

“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 quantitiesrecovered 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 ofa given date, based on: (i) analysis of drilling, geological, geophysical and engineering data; (ii) the use of established technology; and (iii) specified economicconditions, 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, whencompared to the cost of drilling a well) is required to render them capable of production. They must fully meet the requirements of the reservesclassification (proved, probable) to which they are assigned.

References in this presentation to “2P reserves” and “contingent resources” refer to gross proved plus probable reserves and gross best estimate contingentresources, respectively.

Other DefinitionsThroughout this presentation, 7G uses the terms “sustaining capital”. This measure does not have any standardized meaning and therefore should not beused 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 productionfrom existing facilities at current levels.


DEFINITIONS AND ABBREVIATIONSA

AECO

Alliance

avg

B or bn

bbl or bbls

BC

Bcf

Boe or BOE

Btu

C*

°C

CAD or C$ or $

Capex

CDN

CDP

CF

CGR

CG

COLC

CO2e

COGE Handbook

or COGEH

CROIC

C2

C3

C4

C5 or C5+

d

D&C

DCET

DD&A

Deep Southwest

E

EBITDA

ESG

E&P

FCF

FDC

FX

G&A

G&G

GHGe

GJ

GTN

annual

physical storage and trading hub for natural gas on the TransCanada Alberta

transmission system

Alliance pipeline

average

billion

barrels or barrels

British Columbia

billion cubic feet

barrels of oil equivalent

British thermal units

Alberta drilling and completion cost allowance

degrees Celsius

Canadian dollars

capital expenditures

Canadian

CDP Worldwide (formerly, the Carbon Disclosure Project)

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

expected

earnings before interest, taxes, depreciation and amortization

environmental, social, and governance

exploration & production

free cash flow

future development costs

foreign exchange rate

general and administrative expense

geology and geophysics

greenhouse gas equivalent

Gigajoule

Gas Transmission Northwest LLC

H1

H2

H2S

HH or Hhub or Hub

Hz

IFRS

IP

IPO

IRR

ISS

Km

Kpa

LMR

LNG

LGR

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

PIR

PP&E

psi

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

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



natural gas liquids

Natural Gas Pipeline Company of America pipeline system

NOVA Gas Transmission Ltd. pipeline system

net present value

New York Mercantile Exchange

operating expense

profit to investment ratio

property, plant and equipment

pounds per square inch

Q1 or 1Q

Q2 or 2Q

Q3 or 3Q

Q4 or 4Q

R&D

Rich Gas

ROCE

ROY

SEDAR

Sh

Super Pad

TCPL or TC

TSX

TRIF

TTM

US

USD or US$

Wapiti

WCS

WCSB

WTI

YE

YTD

Y/Y

1P

2P

2C

$MM or MM$

Δ

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

TC Energy

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

Brian Newmarch

Vice President, Capital Markets and Stakeholder Engagement

1 . 4 0 3 . 7 6 7 . 0 7 5 2

[email protected]

Ryan Galloway

Director, Investor Relations

1 . 4 0 3 . 7 1 8 . 0 7 0 9

[email protected]

FOR MORE INFORMATION

www.7genergy.com

TSX: VII

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