providing responsibly developed energy to the world · h2/20 production 205 - 215 mboe/d average...

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

TSX: VII

Providing Responsibly Developed Energy to the World

March 2020

2©2020 Seven Generations Energy Ltd

CANADA’S LARGEST

PRODUCER OF

CONDENSATE

• Canada’s most valuable hydrocarbon• Structurally short market drives

price premium

• $4.0B Enterprise Value (1)(2)(3)

• $1.8B market cap, $2.2B net debt(3)

• 335 million shares outstanding

• 208 thousand boe/d(4)

(36% condensate, 22% other NGLs, 42% gas)

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

OVERVIEW FINANCIAL HIGHLIGHTS SUSTAINABILITY BUDGET DETAILS APPENDIXSTRATEGY ASSET OVERVIEW

1) February 28, 2020 share price & shares outstanding as of December 31, 2019.2) US$1.575B in senior unsecured notes converted at $1.3407 CAD/USD plus adjusted net working capital deficiency and long-term lease liabilities as of December 31, 2019 of $54 MM.3) 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


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.

$4.00

$4.50

$5.00

$5.50

$6.00

2017 2018 2019 2020E

Operating Costs($ per boe)

$2.0

$2.5

$3.0

$3.5

$4.0

2017 2018 2019 2020E

Drilling Costs($MM per well)

$2

$3

$4

$5

$6

$7

$8

2017 2018 2019 2020E

Completion Costs($MM per well)



FOCUSED ON THE SHAREHOLDERPrioritizing per-share value creation over volume creation

1) Ranges in “Funds Flow Per Share” are based on 2020 budget assumptions of US$50/bbl of WTI and US$2.50 Henry Hub, with an assumption of $60/bbl in the upside sensitivity case. 2) For projected for 2020 additional information see “Forward-Looking Information Advisory” in the “Important Notice” that appears at the end of the presentation.3) For additional information see “Note Regarding Product Types” in the “Important Notice” that appears at the end of the presentation. Assumes that the company will repurchase the maximum number of shares permitted to be repurchased under the company’s current normal course issuer bid4) For additional information see “Non-GAAP Measures Advisory” in the “Important Notice” at the end of the presentation.

$0.00

$2.00

$4.00

$6.00

2014 2015 2016 2017 2018 2019 2020E

Funds Flow Per Share(1)(2)

$0

$100

$200

$300

Q4/2018 Q1/2019 Q2/2019 Q3/2019 Q4/2019

Cumulative Share Buyback(2)

$MM of Buybacks

0

200

400

600

800

2014 2015 2016 2017 2018 2019 2020E

Production Per Share(2)(3)

Boe/d per million diluted shares

$0.00

$1.00

$2.00

2014 2015 2016 2017 2018 2019

Adjusted Net Income Per Diluted Share(4)



LEVERAGING PAST INVESTMENTSDriving free cash flow and optionality

1) 2020 full-year budgeted assumptions include US$50/bbl WTI, US$2.50/MMbtu Henry Hub, US$5/bbl condensate differentials. Funds flow and free cash flow shown above use the same assumptions with $60/bbl WTI price. For additional information see “Forward-Looking Information Advisory” in the “Important Notice” that appears at the end of this presentation.

2) For additional information see “Non-GAAP Measures Advisory” in the “Important Notice” that appears at the end of the presentation.

0%

50%

100%

150%

200%

250%

300%

350%

400%

2014 2015 2016 2017 2018 2019 2020E

Capital Investments(1)

As a percentage of funds flow

-$1,000

-$800

-$600

-$400

-$200

$0

$200

$400

2014 2015 2016 2017 2018 2019 2020E

Free Cash Flow(1)(2)

($MM)


Total Capital

Facilities Capital


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 repurchase of the maximum number of common shares the company is authorized to repurchase under the company’s current normal course issuer bid. 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

CapitalSustaining

Capital

Growth

Major Infra

Delineation

DelineationDelineation

Value Enhancing

Value Enhancing

Value Enhancing

$40 WTI

$50 WTI

$60 WTI

$70 WTI

$0

$200

$400

$600

$800

$1,000

$1,200

$1,400

$1,600

$1,800

2018 Actual 2019 Actual 2020 Budget 2021 Budget 2022 Budget Adjusted Funds FlowSensitivity

Annual free cash flow potentialat $55-$70 WTI by 2022

With a long inventory runway

Substantial

364MillionShares Outstanding(3)




91WellsOn Production

83WellsOn Production

75-80WellsOn 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, WC3) 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

Best-ranked carbon disclosure within Canadian oil & gasA-

Lower per-boe GHGefootprint than industry average(2)

80%


2020 Capital Budget & Guidance

Production & Supporting Infrastructure $1.0 billion

Value Enhancement Projects & Delineation $0.1 billion

Total Capital Investment $1.1 billion

H1/20 Production 190 - 200 Mboe/d

H2/20 Production 205 - 215 Mboe/d

Average Production 200 – 205 Mboe/d

Development Wells On Stream (#) 75 – 80

Percent Liquids 56 - 60%

Percent Condensate 34 - 38%

Royalty Rate at US$50 WTI 5 - 7%

Royalty Rate at US$60 WTI 7 - 9%

Operating Expenses ($/boe) $4.75 - $5.25

Transportation ($/boe) $6.75 - $7.25

G&A ($/boe) $0.85 - $0.95

Interest ($/boe) $1.80 - $1.90

$1.1B


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 $50 WTI / $2.50 Henry Hub

Drilling

Completions

Equip& Tie

Pads& Pipes

Other

Delineation

Value Enhancing

Nest 2

Nest 1 Nest 3


• Nest 2Primary Liquids-Rich Region

• Nest 3New High-Deliverability 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

OPERATING OUR BUSINESS


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

A world-class asset on which we’ve built the company

Alliance

NGTL


1) For additional information, see “Forward-Looking Information Advisory”, “Presentation of Oil and Gas Information” and “Note Regarding Oil and Gas Metrics” in the “Important Notice” at the end of this presentation.2) Represents the before tax net present value of future net revenue discounted at a rate of 10%, estimated by McDaniel, as at December 31, 2019.

Highly efficient conversion of barrels into cash flow

2019 RESERVES

Decline moderation on trackBetter vintage mix = lower decline rates

Low-40% decline rates entering 2020


Y1Y2

Y3

Y4+

Weighted average production ageat year-end 2018

1.5YearsWeighted average production ageat year-end 2019

2.0Years Y1

Y2

Y3

Y4+

1.6xPDP recycle ratio

Barrels of oil equivalent 2P reserves as at Dec 31, 2019

1.6Billion2P reserve value(2)

$12.6Billion

PDP FD&A cost

$13.06per boe

$6.50

$7.00

$7.50

$8.00

$8.50

2015 2016 2017 2018 2019

Future Development Costs Improving(2P FDC $/boe)

Reduced 2P future development capital vs 2018 reserve report

$940Million

(1)


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$50/bbl WTI, -$5/bbl Edmonton condensate differentials, US$2.50/Mmbtu Henry Hub.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)

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) $9.25 MM $9.25 MM $9.25 MM $9.25 MM

CGR (IP365) (bbl/mmcf)

300 170 55 210

% Condensate (IP365)

64% 50% 25% 53%

Ec

on

om

ics

at

$5

0/$

2.5

0

Single Well(1)

NPV $8.1 MM $9.3 MM $9.3 MM $8.8 MM

IRR 81% 106% 101% 95%

PIR 0.9x 1.0x 1.0x 1.0x

FullCycle(2)

NPV $4.2 MM $4.6 MM $4.6 MM $4.4 MM Emerging Development Areas

IRR 38% 44% 53% 43% Lower Montney

WapitiRich Gas

CretaceousPIR 0.4x 0.5x 0.5x 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 Planned

~9 ~50 ~13 ~72 ~6-8 - - -


TSX: VII

www.7genergy.com

TSX: VII


GUIDING PRINCIPLEStakeholder 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 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.



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 ~650 Mbbl/d exceeds local supply by ~250 Mbbl/d

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


$10

$30

$50

$70

2015 2016 2017 2018 2019

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

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

250 Mbbl/d+ gap between

supply & demand

2018 2019 2020E 2021E 2022E

Demand

WCSB Supply

Condensate is Canada’s premium liquids product


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) 2019 average benchmark prices sourced from Bloomberg.

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

• Diversified premium markets includes US LNG optionality


NGPL155 MMcf/d

Alliance500 MMcf/d

TCPL77 MMcf/d

GTN90 MMcf/d

Natural Gas

Condensate

NGLs

2020 Revenue Mix

$0.00

$1.00

$2.00

$3.00

Chicago Gulf Malin Dawn AECO

2019 Benchmark Prices (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

• H2/20+ to see increased activity levels


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

• Sub-$8,000/boe/d drill, complete, equip and tie-in capital efficiency

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


High-deliverability 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


US$425MM6.75%

US$450MM6.875%

US$700MM5.375%

$0

$200

$400

$600

$800

$1,000

2020 2021 2022 2023 2024 2025

Long Term Maturities, Fixed Coupon Senior Unsecured Notes

RISK MANAGEMENT

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

Total liquidity- $1.4B available on $1.4B facility - $0.5B accordion- 2024 maturity

$1.9Billion

0.0x

0.5x

1.0x

1.5x

2.0x

$50 WTI $60 WTI $70 WTI

Favorable Leverage2020E net debt to trailing 12-month adjusted EBITDA

To first maturityCall premiums step down mid-2020

3.5Years


RISK MANAGEMENT

1) Targeted percentages are based on total production net of royalties2) For additional information, see “Forward-Looking Information Advisory” and “Note Regarding Product Types” in the “Important Notice” at the end of this presentation.


Commodity hedgingCapital investment

ProtectRevenue volatility

ReduceBalance sheet

Preserve

Year 1

35%-65%

Year 2

10%-35%

Year 3

0%-20%

Rolling 3-Year Targets(1)

2020E Condensate 2020E Natural Gas

55%

At US$52-57/bblWTI

Hedged

Un-hedgedUn-hedged

Hedged

39%

At US$2.65/MMBtuHenry Hub



CURRENT HEDGE POSITIONSAs at December 31, 2019



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). 2017 figures have been adjusted to conform to this current period presentation.3) Excludes the purchase and resale of liquids and natural gas in respect of transportation commitment optimization and marketing activities. Refer to the Q4 2019 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 Q4 2019 Q3 2019 Q2 2019 Q1 2019 Q4 2018 Q3 2018 Q2 2018 Q1 2018 Q4 2017 Q3 2017 Q2 2017 Q1 2017 YE 2019 YE 2018 YE 2017

Average daily production (1)

Condensate (2) (mbbl/d) 75.0 75.5 75.9 72.7 81.8 87.3 69.0 67.3 70.0 64.5 59.0 51.6 74.8 76.4 61.3

Natural gas (MMcf/d) 523.1 515.3 489.6 483.6 515.4 511.3 461.3 473.3 493.4 453.2 409.6 384.5 503.0 490.5 435.5

Other NGLs (2) (mbbl/d) 45.9 43.2 44.3 44.1 47.4 47.3 41.2 41.5 45.1 43.9 37.9 37.4 44.4 44.4 41.1

Total (mboe/d) 208.1 204.6 201.8 197.4 215.1 219.8 187.1 187.7 197.3 183.9 165.2 153.1 203.0 202.6 175.0

CGR Ratio 143 147 155 150 155 175 150 142 142 142 144 134 149 156 141

LGR Ratio 88 84 90 91 92 93 89 88 91 97 93 97 88 91 94

Realized Prices

Condensate (2) ($/bbl) 66.39 65.59 71.91 63.00 53.57 79.26 81.67 73.39 67.95 54.95 58.28 63.84 66.76 71.63 61.28

Natural gas ($/Mcf) 3.25 2.85 3.29 4.32 4.77 3.65 3.79 3.54 3.53 3.46 4.09 4.36 3.41 3.98 3.84

Other NGLs (2) ($/bbl) 10.75 2.74 4.19 7.46 8.44 14.02 13.39 13.33 18.30 15.18 11.45 12.45 6.34 12.21 14.56

34.48 31.97 35.95 35.44 33.66 42.99 42.42 38.19 37.13 31.43 33.58 35.52 34.44 39.33 34.45

Netbacks (4)

Liquids and natural gas sales ($/boe) 34.48 31.97 35.95 35.44 33.66 42.99 42.42 38.19 37.13 31.43 33.58 35.52 34.44 39.33 34.45

Royalties ($/boe) (2.62) (1.99) (2.19) (2.30) (0.99) (2.20) (0.96) (1.12) (1.18) (0.86) (0.62) (1.22) (2.28) (1.34) (0.97)

Operating expense ($/boe) (4.43) (4.81) (5.00) (4.93) (5.25) (5.22) (6.00) (5.73) (5.69) (5.43) (6.24) (4.99) (4.79) (5.52) (5.60)

Transportation, processing and other expense ($/boe) (7.01) (6.46) (6.64) (6.65) (7.07) (6.14) (6.93) (6.24) (6.43) (6.47) (5.88) (5.39) (6.69) (6.65) (6.09)

Operating netback before the following (4) ($/boe) 20.42 18.71 22.12 21.56 20.35 29.43 28.53 25.10 23.83 18.67 20.84 23.92 20.68 25.82 21.79

Realized hedging gain (loss) ($/boe) 0.55 1.63 0.04 (0.34) (1.58) (1.79) (1.04) (0.78) 0.38 0.84 0.12 (0.52) 0.48 (1.33) 0.25

Marketing Income (4)(5) ($/boe) 0.18 0.19 0.07 0.77 0.20 0.28 0.53 0.62 0.65 0.27 0.43 0.17 0.30 0.39 0.39

Operating netback (4) ($/boe) 21.15 20.53 22.23 21.99 18.97 27.92 28.02 24.94 24.86 19.78 21.39 23.57 21.46 24.88 22.43

General and administrative expense ($/boe) (0.83) (0.84) (0.85) (0.94) (0.91) (0.66) (0.82) (0.65) (0.65) (0.65) (0.82) (0.79) (0.86) (0.76) (0.72)

Finance expense and other ($/boe) (1.87) (1.60) (2.03) (1.98) (1.07) (1.42) (1.71) (1.83) (2.06) (2.09) (4.30) (3.01) (1.87) (1.51) (2.81)

Funds flow per boe (4) ($/boe) 18.45 18.09 19.35 19.07 16.99 25.84 25.49 22.46 22.15 17.04 16.27 19.77 18.73 22.61 18.90

FINANCIAL RESULTS (4)

Condensate (2) ($MM) 458.1 455.6 496.7 412.2 403.2 636.6 512.8 444.5 437.6 326.1 312.9 296.5 1,822.6 1,997.3 1,373.1

Natural gas ($MM) 156.6 135.3 146.6 187.9 225.7 171.8 159.2 156.1 160.3 144.2 152.4 150.8 626.4 712.6 607.7

Other NGLs (2) ($MM) 45.4 10.9 16.9 29.6 36.8 61.0 50.2 49.8 76.0 61.3 39.5 42.1 102.8 197.8 218.9

Liquids and natural gas sales (3) ($MM) 660.1 601.8 660.2 629.7 665.7 869.4 722.2 650.4 673.9 531.6 504.8 489.4 2,551.8 2,907.7 2,199.7

Royalties ($MM) (50.2) (37.5) (40.2) (40.9) (19.5) (44.4) (16.4) (18.9) (21.5) (14.5) (9.3) (16.8) (168.8) (99.2) (62.1)

Operating expense ($MM) (84.9) (90.6) (91.8) (87.5) (103.8) (105.5) (102.2) (96.8) (103.3) (91.8) (93.9) (68.8) (354.8) (408.3) (357.8)

Transportation, processing and other expense ($MM) (134.3) (121.6) (121.9) (118.1) (139.9) (124.2) (118.0) (109.7) (116.8) (109.4) (88.3) (74.3) (495.9) (491.8) (388.8)

Operating netback before the following (4) ($MM) 390.7 352.1 406.3 383.2 402.5 595.3 485.6 425.0 432.3 315.9 313.3 329.5 1,532.3 1,908.4 1,391.0

Realized hedging gain (loss) ($MM) 10.5 30.6 0.8 (6.0) (31.2) (36.2) (17.7) (13.1) 6.9 14.2 1.8 (7.2) 35.9 (98.2) 15.7

Marketing Income (4)(5) ($MM) 3.4 3.6 1.3 13.6 3.9 5.7 9.1 10.0 11.8 4.6 6.3 2.3 21.9 28.7 25.0

Operating netback (4) ($MM) 404.6 386.3 408.4 390.8 375.2 564.8 477.0 421.9 451.0 334.7 321.4 324.6 1,590.1 1,838.9 1,431.7

Revenue (6) ($MM) 669.6 718.0 795.5 546.3 1,146.8 809.0 560.4 653.7 652.3 563.7 608.8 629.8 2,729.4 3,169.9 2,454.6

Funds flow (4) ($MM) 353.2 340.5 355.3 338.8 336.2 522.5 434.0 379.5 402.0 288.3 244.6 272.4 1,387.8 1,672.2 1,207.3

Net Income (loss) ($MM) 82.6 85.1 295.3 10.8 245.4 196.4 (24.6) 22.7 83.1 85.7 178.1 215.6 473.8 439.9 562.5

Adjusted net income ($MM) 89.7 78.5 96.8 84.0 66.3 208.3 169.6 129.4 128.6 63.4 59.5 74.8 349.0 573.6 326.3

Free cash flow (4) ($MM) 120.3 55.9 44.2 (62.1) 73.9 164.3 (128.6) (203.1) 80.0 (166.0) (267.9) (90.2) 158.3 (93.5) (444.1)

Capital investments

Drilling and completions ($MM) 132.5 171.0 172.9 231.4 148.9 232.6 335.9 319.6 167.4 252.8 342.3 259.4 707.8 1,037.0 1,021.9

Facilities and infrastructure ($MM) 59.0 76.9 119.5 132.2 67.7 90.8 179.3 207.0 115.0 176.5 153.9 85.2 387.6 544.8 530.6

Land and other ($MM) 41.4 36.7 18.7 37.3 45.7 34.8 47.4 56.0 39.9 25.0 16.3 17.7 134.1 183.9 98.9

Total capital investments ($MM) 232.9 284.6 311.1 400.9 262.3 358.2 562.6 582.6 322.3 454.3 512.5 362.3 1,229.5 1,765.7 1,651.4


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”, “7G”, “VII”, the “company” or the “Company”)and of the information contained in this presentation. Without limitation, prospective investors should read the record of publicly filed documents relatingto the Company, consider the advice of their financial, legal, accounting, tax and other professional advisors and such other factors they considerappropriate in investigating and analyzing the Company. An investor should rely only on the information provided by the Company and is not entitled torely on parts of that information to the exclusion of others. The Company has not authorized anyone to provide investors with additional or differentinformation, and any such information, including statements in the media about Seven Generations, should not be relied upon. In this presentation, unlessotherwise 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-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” and “free cash flow”.

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. 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 these 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.

“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.

“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.

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 cost improvement, improved capital and operating efficiencies, value creation, freecash flow generation, and plans to prioritize per share value creation over volume creation; expected drilling inventory/ potential drilling opportunities;expected number of years to develop drilling inventory/potential drilling opportunities; upside potential of the company’s properties; details and forecastsrelated to the 2020 budget, including those contained on the slide titled “2020 Budget Details”, and among them: expected production and supportinginfrastructure capital investments, expected capital investments in value enhancing projects and delineation and total capital investments in 2020, capitalinvestment as a percentage of funds flow and free cash flow in 2020, average daily production for the first half, second half and full-year in 2020, thenumber of development wells to be brought on-stream, liquids and condensate yields, the percentage of 2020 condensate and natural gas production thathas been hedged, royalty rates, operating expenses, drilling and completions costs, transportation expenses, G&A expenses, interest expenses, expectedfunds flow per share and expected production per share; the product composition, productivity and deliverability of various current and futuredevelopment areas; the ultra-rich condensate production expected from the Nest 1 region; transportation and processing capacity; forecast net debt totrailing 12-month adjusted EBITDA at different commodity price scenarios; forecast supply and demand of condensate; forecast full-cycle and half-cycleeconomics, including single well economics, IRRs, break-even costs, NPVs and PIRs; expectation that the area recently added to Nest 2 will have sweet,liquids rich condensate production and will be analogous (in terms of production) to locations in North-West Nest 2; hedge targets; objectives of hedgingprogram; access to sales points; expected future sales points; potential to expand the boundary of the Nest 3 area; potential to expand the inventory persection and forecast NPV per section with the potential addition of Lower Montney locations; future capital efficiencies; delineation potential and planneddelineation; and the references to development area forecasts and type-curve estimates. In addition, information and statements in this presentationrelating to reserves, related future development costs, related net present value of future net revenue, and contingent resources are deemed to be forward-looking statements as they involve the implied assessment, based on certain estimates and assumptions, that the reserves and/or resources described existin 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; therepurchase of the maximum number of common shares authorized to be repurchased under the company’s current normal course issuer bid program; 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 the following commodity pricing assumptions: US$50.00/bbl WTI,US$2.50/MMbtu NYMEX/HH and 0.75 USD/CAD FX. NGLs as % of WTI: C3 26%, C4 30%, C5 – $5 USD/bbl differential. AECO Basis US$1.15/MMbtu. Operatingcost assumptions reflect recent actual cost trends with adjustments to address planned activity levels. Royalty rate assumptions were calculated using aprice range of US$50-US$60/bbl WTI, net of credits as of December 31, 2019 and projected C* for new wells to be drilled in 2020. Royalty rate assumptionsare net of expected gas cost allowance investments in gas plants. G&A cost assumptions reflect recent actuals and expectations for a staff count andinformation 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 range of US$50-US$65/bbl, net of credits as of Dec.31/19 and projected C* for new wells drilled or to be drilled in 2020. Royalty rates werecalculated net of expected 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”), which is available on theSEDAR website at www.sedar.com, including, but not limited to: volatility in market prices and demand for oil, NGLs and natural gas and hedging activitiesrelated thereto; general economic, business and industry conditions; variance of the Company’s actual capital costs, operating costs and economic returnsfrom those anticipated; the ability to find, develop or acquire additional reserves and the availability of the capital or financing necessary to do so onsatisfactory terms; risks related to the exploration, development and production of oil and natural gas reserves and resources; negative public perception ofoil sands development, oil and natural gas development and transportation, hydraulic fracturing and fossil fuels; actions by governmental authorities,including changes in government regulation, royalties and taxation; political changes; potential legislative and regulatory changes; the rescission, oramendment to the conditions, of groundwater licenses of the Company; management of the Company’s growth; the ability to successfully identify andmake attractive acquisitions, joint ventures or investments, or successfully integrate future acquisitions or businesses; the availability, cost or shortage of rigs,equipment, raw materials, supplies or qualified personnel; the adoption or modification of climate change legislation by governments; potential impacts ofclimate change on the Company’s operations; uncertainty associated with estimates of oil, NGLs and natural gas reserves and resources and the variance ofsuch estimates from actual future production; dependence upon compressors, gathering lines, pipelines and other facilities, certain of which the Companydoes not control; the ability to satisfy obligations under the Company’s firm commitment transportation and processing arrangements; the export and saleof natural gas to the United States; the uncertainties related to the Company’s identified drilling locations; the high-risk nature of successfully stimulatingwell productivity and drilling for and producing oil, NGLs and natural gas; operating hazards and uninsured risks; the risks of fires, floods and naturaldisasters, which could become more frequent or of a greater magnitude as a result of climate change; the possibility that the Company’s drilling activitiesmay encounter sour gas; execution risks associated with the Company’s business plan; failure to acquire or develop replacement reserves; the concentrationof the Company’s assets in the Kakwa area; unforeseen title defects; Indigenous 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 completiontechnique risks and failure of drilling results to meet expectations for reserves or production; limited intellectual property protection for operating practicesand dependence on employees and contractors; third-party claims regarding the Company’s right to use technology and equipment; expiry of certainleases for the undeveloped leasehold acreage in the near future; failure to realize the anticipated benefits of acquisitions or dispositions; failure of propertiesacquired now or in the future to produce as projected and inability to determine reserve and resource potential, identify liabilities associated with acquiredproperties or obtain protection from sellers against such liabilities; government regulations; changes in the application, interpretation and enforcement ofapplicable 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 andthe Canadian oil and gas industry; alternatives to and changing demand for petroleum products; extensive competition in the Company’s industry; changesin the Company’s credit ratings; third party credit risk; dependence upon a limited number of customers; lower oil, NGLs and natural gas prices and highercosts; failure of seismic data used by the Company to accurately identify the presence of oil and natural gas; risks relating to commodity price hedginginstruments; terrorist attacks or armed conflict; cyber security risks, loss of information and computer systems; inability to dispose of non-strategic assets onattractive terms; the potential for security deposits to be required under provincial liability management programs; reassessment by taxing and royaltyauthorities of the Company’s prior transactions and filings; variations in foreign exchange rates and interest rates; risks associated with counterparties in riskmanagement activities related to commodity prices and foreign exchange rates; sufficiency of insurance policies; potential for litigation; variation in future

calculations of non-IFRS measures; breach of 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 theCompany’s senior notes and 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 related future development costs, the net present value of future net revenue attributable to the company’sreserves and the Company’s contingent resources that are contained herein are based upon reports prepared by McDaniel & Associates Consultants Ltd.(“McDaniel”), the Company’s independent qualified reserves evaluator, as at December 31, 2018 and/or December 31, 2019 (the “McDaniel Reports”). Theestimates of reserves and contingent resources provided in this presentation are estimates only and there is no guarantee that the estimated reserves andcontingent resources will be recovered. Actual reserves and contingent resources may be greater than or less than the estimates provided in this in thispresentation and the differences may be material. There is no assurance that the forecast price and cost assumptions applied by McDaniel in evaluatingSeven Generations’ reserves and contingent resources will be attained and variances could be material. There is uncertainty that it will be commerciallyviable 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 AIF and the annual informationform dated February 27, 2019 for the year ended December 31, 2018, which are available on the SEDAR website at www.sedar.com, and contain importantadditional information regarding the independent reserves and contingent resource evaluations that were conducted by McDaniel, as presented in theMcDaniel Reports, and a description of, and important information about, the reserves and resources terms used in this presentation.


IMPORTANT NOTICENote Regarding Oil and Gas MetricsThis presentation includes certain oil and gas metrics, including “barrels of oil equivalent” (or “boes”), “weighted average production age”, “PDP F&D cost”,“PDP FD&A cost” and “PDP recycle ratios”, which do not have standardized meanings or standard methods of calculation and therefore such measures maynot be comparable to similar measures used by other companies and should not be used to make comparisons. Such metrics have been included hereinto provide readers with additional information to evaluate the Company’s performance; however, such measures are not reliable indicators of the futureperformance of the Company, and future performance may not compare to the performance in previous periods.

Unless otherwise specified, all production is reported on the basis of the company’s working interest (operating and non-operating) before the deduction 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.

Weighted average production age has been calculated by collecting total corporate production contributed by each producing well at a point in time, andthen grouping and summing the production from each well based on the reported year of first production from each well.

PDP reserve capital is defined as total capital investments during the year plus any changes in future development capital.

PDP reserves additions is defined as the sum of all extensions/improved recoveries, technical revisions and economic factors for the year.

PDP F&D cost has been calculated by dividing the PDP Reserve Capital by the PDP Reserves Additions.

PDP FD&A cost has been calculated by dividing the PDP Reserve Capital plus acquisition costs, by the PDP Reserves Additions including acquired PDPReserves.

PDP recycle ratios have been calculated by taking the operating netback prior to gains from hedging and marketing and dividing by the PDP F&D cost.

For important additional information regarding the independent reserves evaluations that were conducted by McDaniel, please refer to the AIF, as well asthe annual information form dated February 27, 2019 for the year ended December 31, 2018, which are available on the SEDAR website at www.sedar.com.

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 and

Climate 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 200 - 205 mboe/d for 2020. Seven Generations expectsthat approximately 34% - 38% of that production will be comprised of condensate, 37% - 41% will be comprised of shale gas, 22% will be comprised ofother 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, 2017 51.6 37.4 341.9 42.6 153.1June 30, 2017 59.0 37.9 382.0 27.6 165.2September 30, 2017 64.5 43.9 422.3 30.9 183.9December 31, 2017 70.0 45.1 469.1 24.3 197.3March 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 30.7 208.1

Year endedDecember 31, 2017 61.3 41.1 404.2 31.3 175.0December 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 – Ultra-rich condensate region” has been obtained by 7G from publicsources 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 isaccurate or was provided in accordance with applicable regulatory requirements. All of the competitor wells referenced were drilled in the Montneyformation. The information is considered to be relevant because the geology of properties owned by 7G are considered to be similar to the competitorproperties that are referenced. Significant production or pressure decline was noted in the data for the flowtests and/or early production history, andpressure transient analysis and well test interpretation had not yet been carried out at the time the data was posted. As such, the information should beconsidered to be preliminary until further analysis and interpretation has been completed.

The Nest 1 well that is described on that same slide was drilled in the middle interval of the Montney formation in the company’s Nest 1 area. The 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

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

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

PDP

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

gross proved developed producing reserves

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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