TSX: VII.TO

High Growth, Low Supply Cost

Montney DeveloperSeptember 2017

7G Corporate Overview

2

7G Capitalization & Key Corporate Statistics

Ticker symbol - TSX VII

Share Price(1) $17.99

Basic Market Cap(1) $6.4 billion

Net Debt(2)(4) $1.7 billion

Enterprise Value $8.1 billion

Available Funding(3)(4) $1.6 billion

2017 Production Guidance (% Liquids)175 -180 MBOE/d

(55% - 60%)

2017 Capital Investment Guidance $1.5 - 1.6 billion

Q2 2017 Production165 Mboe/d

(59% liquids)

Q2 2017 Funds from Operations(4) $268 million

(1) August 29, 2017 share price & shares outstanding

(2) US$1.575B in senior unsecured notes converted at $0.80 USD/CAD less adjusted net working capital as of June 30, 2017 of $247 MM

(3) Adjusted net working capital as of June 30, 2017 of $247 MM plus available credit facility capacity less cash collateral for letters of credit

(4) Non-IFRS Financial Measure. For additional information see “Non-IFRS Measures Advisory” in the “Important Notice” that appears at the end of the presentation

(5) Average first half 2017 trading volumes across all exchanges

Key Business Principles

3

Position in gathering, processing and transportation opportunities

Leverage market access to capture premium markets

Combine resource selection with innovation, technology and efficiency

Remain among North America’s lowest supply cost gas developers

Differentiate in the service of all stakeholders

Enhance social license by adhering to 7G’s Level 1 Policy Statement

MARKET

ACCESS

STAKEHOLDER

SERVICE

SUPPLY

COST

Earn full cycle returns on capital employed

Generate positive free cash flow

FINANCIAL

SUSTAINABILITY

Building The Premiere Montney Developer

4

7G Historical Quarterly Production by Commodity (Boe/d)

Alberta Condensate Production (Bbls/d)

Source: Peters & Co. Limited Equity Research – May 2017

Project Based Montney Development

• Extensive, scalable, condensate and

liquids-rich Montney land base with

decades of drilling opportunities

• Pad based drilling and completions

development to optimize capital

efficiencies and continuously improve

returns on invested capital

• Integration of Super Pads into major

facilities design to ensure processing

capacity & condensate stabilization for

next stage of production growth

• Sufficient transportation commitments

for both natural gas and liquids to

ensure efficient market access

—

20,000

40,000

60,000

80,000

100,000

120,000

140,000

160,000

180,000

200,000

Q12014

Q22014

Q32014

Q42014

Q12015

Q22015

Q32015

Q42015

Q12016

Q22016

Q32016

Q42016

Q12017

Q22017

2017E

Natural gas - Boe/d

NGLs - Bbl/d

Condensate - Bbl/d

0

50,000

100,000

150,000

200,000

250,000

300,000

Seven Generations

Other Operators

2017 Alberta condensate demand is estimated at ~500,000 bbl/d

7G condensate production currently

accounts for ~20% of Alberta supply

Execution - Consistent Growth & Cost Improvements

5

(1) 2017E production calculated as midpoint of 2017 production guidance of 175,00 – 180,000 BOE/d

(2) Non-IFRS financial measure. Please refer to “Non-IFRS Measures Advisory” in the “Important Notice” at the end of the presentation

(3) Based the reports of McDaniel & Associates Consultants Ltd. (“McDaniel) with effective dates: March 31, 2013; December 31, 2013; December 31, 2014; December 31, 2015; and December 31, 2016. Please refer to the “Important Notice” at the end of the

presentation for additional information pertaining to the reserves evaluations

A demonstrated track record of profitable growth

182283

789 859

1,535

0

200

400

600

800

1,000

1,200

1,400

1,600

1,800

2012 2013 2014 2015 2016

Funds From Operations ($MM) (2)Production (Boe/d) (1) 2P Reserves (MMboe) (3)

Completion Costs per Tonne ($/Tonne)Drilling Costs per Lateral Metre ($/Metre) Average Drilling & Completion Costs ($MM)

$36 $50

$328

$415

$733

$0

$100

$200

$300

$400

$500

$600

$700

$800

2012 2013 2014 2015 2016

4,180 7,78631,136

60,403

117,781

175,000-180,000

0

50,000

100,000

150,000

200,000

250,000

2012 2013 2014 2015 2016 2017E

$0

$500

$1,000

$1,500

$2,000

$2,500

$3,000

$3,500

$4,000

$4,500

2012 2013 2014 2015 2016

$0

$500

$1,000

$1,500

$2,000

$2,500

$3,000

$3,500

$4,000

$4,500

2012 2013 2014 2015 2016$0

$2

$4

$6

$8

$10

$12

$14

$16

$18

$20

2012 2013 2014 2015 2016

Drilling Cost Completion Cost

108.0127.1

186.1 195.5 198.3218.2

241.2

307.7336.3

421.5 428.1

381.5

436.8467.4

502.3

0.0

100.0

200.0

300.0

400.0

500.0

600.0

Q12014

Q22014

Q32014

Q42014

Q12015

Q22015

Q32015

Q42015

Q12016

Q22016

Q32016

Q42016

Q12017

Q22017

2017E

Pro

d/s

h (

Boe/d

per

MM

Share

s)

- Equity issued during quarter

14%

7%

11%10%

12%

5%

7%

5%

15%

6%6%

4%

–

2%

4%

6%

8%

10%

12%

14%

16%

VII Top CanadianLiquids-Rich Gas Peers

Top CanadianGas Weighted Peers

Top U.S.Growth Peers

CR

OIC

(%

)

2013A-2015A 2015A 2016A

Profitable Growth

6

• 7G Quarterly Production per Share

(1) Quarterly average production divided by quarterly weighted average basic share count.

(2) 2017E production calculated as midpoint of 2017 production guidance of 175,00 – 180,000 BOE/d divided by estimated 2017 weighted average basic share count.

Production per share up 139% since IPO

• Historical Cash Return on Invested Capital (CROIC)

Source: CIBC World Markets(1) CROIC calculated as FactSet EBITDA divided by gross PP&E. FactSet EBITDA and CROIC are non-IFRS financial measures. For additional information see “Non-IFRS Measures

Advisory” in the “Important Notice” that appears at the end of the presentation

(2) Peer groups are comprised of: Liquids-Rich - ARX, CR, KEL, NVA | Gas – AAV, BIR, PEY, PPY, SRX, TOU | U.S. Growth – AR, COG, EOG, EQT, PXD, RRC, SWN

VII

223.6

369.5

502.5

0.0

100.0

200.0

300.0

400.0

500.0

600.0

2015 2016 2017E

BO

E/d

per

MM

Sh

are

s

$1.53

$2.30

$0.00

$0.50

$1.00

$1.50

$2.00

$2.50

$3.00

2015 2016

$ p

er

Sh

are

3.1

4.2

0.0

1.0

2.0

3.0

4.0

5.0

6.0

2015 2016

Bo

ep

er

Sh

are

Significant Per Share Growth

7

Creating value through per share growth across all aspects of the business

(1) Based on annual weighted average fully diluted shares outstanding.

(2) 2017E value based on midpoint of 2017 production guidance of 177,500 MBOE/d.

(3) Non-IFRS Financial Measure based on funds from operations divided by weighted average shares outstanding. For additional information see “Non-IFRS Measures Advisory” in the “Important Notice” that appears at

the end of the presentation.

(4) Based on year-end fully diluted shares outstanding and the reserve reports prepared by McDaniel, as at December 31, 2015 and December 31, 2016. Please refer to the “Important Notice” at the end of the

presentation for additional information pertaining to the reserves evaluations.

(5) Debt adjusted per share metrics assume 11.2 MM share dilution based on a $278 MM change in net debt and a $24.79 average 2016 share price .

• Production per Share(1)(2)(5) • Funds Flow per Share(1)(3)(5) • 2P Reserves per Share(4)(5)

356.9Debt Adjusted

Debt Adjusted

$2.22Debt Adjusted

4.1

8

Full Cycle Returns – Improving Type Curves Through Time Assumes: US$50/bbl WTI, US$3.00/MMbtu NYMEX, $0.77 USD/CAD

1) Price Assumptions: $50 US/bbl WTI, $3.00 US/MMBtu NYMEX HH and 0.77 USD/CAD FX. NGLs as % of WTI: C3 35%, C4 50%, C5 90%. Chicago gas discount $0.01 to NYMEX HH. Unit transportation costs: sales gas US$0.92/Mcf. Recovered liquids: $5.80/bbl. Average opex (first 3 years) =

~3.70 $/boe for sweet gas, ~$6.00 for sour gas (Wapiti Curve only). ~15% raw gas shrink. Fixed well operating cost = $20,000/mo. for half cycle, $30,000/mo. for full cycle.

2) Recoveries: NGL recoveries are based on a best estimate of the liquids to be extracted at 7G’s wholly owned plants in Alberta and the liquids to be processed by Aux Sable at its facilities near Chicago, Illinois pursuant to the terms of the rich gas premium agreement between 7G and Aux Sable, which

depends upon an assumed heating value and has been assumed to extend for the entire productive life of the wells.

3) Other Type-curve Assumptions: For a description of the assumptions that have been made by the company in preparing its type-curves and in determining the estimated number of potential drilling opportunities, and for important additional information about the company’s type-curve forecasts and

estimates of potential drilling opportunities, please refer to the “Important Notice” at the end of this presentation.

4) Half-Cycle economics: includes only the cost to drill, complete, tie, and equip well. Does not include all costs for Super Pad infrastructure, central processing, regional gathering, condensate stabilization, other infrastructure, land acquisition, corporate overhead (G&A), financing or corporate taxes.

These economics are intended to represent the marginal return of a single well investment on an existing Super Pad. No adjustments have been made for downtime or facility constraints.

5) Full-cycle economics: Include a $4.10/boe burden to carry infrastructure costs including central plant processing (NGL extraction), Super Pad build, regional gathering and sales pipelines and condensate stabilization. A $0.90/boe burden to carry corporate overhead (G&A). Land acquisition, financing

costs and corporate taxes have been excluded. Sunk investments to test, demonstrate, delineate and commercialize plays has also been excluded; the period of time (and related capital carrying costs) required to acquire, test and delineate the lands prior to commercial development has not been

factored into this analysis. It assumes a forward-looking development with existing knowledge of the risk profile of 7G’s Nest lands, including but not limited to reservoir deliverability, liquid-gas ratios, H2S content, gas and liquids compositions, and also assumes available pipeline transportation

capacity with firm gas and liquids transportation.

2015 Type

Curve

2016 Type

Curve

2017 program

(high intensity)

Nest 2 Nest 2 Nest 2

Well/Capital Assumptions

Lateral length (m) 2,450 2,700 2,700

Stage count (#) 28 28 36

Tonnage (Tonnes/stage) 120 160 160

Total well cost (DCET) ($MM) $11.0 $11.0 $12.3

Production

Condensate gas ratio (bbls/MMcf) 118 118 118

Condensate production (bbls/d) 491 564 714

NGL production (bbls/d) 287 330 422

Raw gas production (mcf/d) 3,984 4,573 5,855

Recoveries

Condensate recovery (mbbls) 468 510 510

NGL recovery (C2-C4) (mbbls) 502 548 548

Natural gas recovery (bcf) 5.9 6.4 6.4

Total EUR (mboe) 1,945 2,122 2,122

Economics

IRR (%) 98% 138% 184%

NPV10 ($MM) $13.6 $17.1 $19.4

Natural gas supply cost (US$/MMBTU) $0.24 -$0.22 -$0.33

IRR (%) 52% 77% 103%

NPV10 ($MM) $7.3 $10.1 $11.6

Natural gas supply cost (US$/MMBTU) $1.70 $1.23 $1.11

Half

Cycle

Fu

ll

Cycle

IP 3

65

Inp

uts

EU

R

Production

BudgetCapital

Budget • Raw Gas Type Curve

0

1,000

2,000

3,000

4,000

5,000

6,000

7,000

8,000

9,000

0 50 100 150 200 250 300 350

Gas R

ate

(M

cf/

d)

Producing Days

2015 Nest 2 Type Curve2016 Nest 2 Type CurveNest 2 High Intensity

• Wellhead Condensate Curve

0

200

400

600

800

1,000

1,200

1,400

1,600

1,800

0 50 100 150 200 250 300 350

Condensate

Rate

(bbl/d)

Producing Days

2015 Nest 2 Type Curve2016 Nest 2 Type CurveNest 2 High Intensity

The Asset - Inventory by Development Area

9

Decades of liquids rich Montney drilling inventory, future upside in Deep SW, Wapiti, Rich Gas & shallower targets (1) For important supplemental information regarding the company’s estimated number of potential drilling opportunities, please refer to the “Note Regarding Potential Drilling Opportunities” in the “Important Notice”

at the end of this presentation.

(2) NYMEX Henry Hub price required for 20% pre-tax IRR. Assumes US$50/bbl WTI, US$3.00/MMbtu NYMEX. Half-cycle economics.

Nest 2

• ~ 800 locations(1)

• <$0.00/MMbtu supply cost(2)

• Majority of 2017 activity

Nest 1

• ~ 500 locations(1)

• $1.47/MMbtu unoptimized supply

cost(2)

Wapiti & Rich Gas

• ~ 1,000 locations(1)

• <$2.25/MMbtu unoptimized supply

cost(2)

• Testing/delineation in 2017

Deep SW

• 315 net sections

• Significant unverified resource

• Testing/delineation in 2017

Lower Montney

• ~ 800 net sections

• 100 m thick

• Significant unverified resource

• Testing/delineation in 2017

Cretaceous

• 215 net sections

• Multiple target zones

• Significant unverified resource

Current Development

Future Upside

Nest 1/Nest 2 Boundary Results:

90 day cumulative condensate

production of >170 Mbbls and 0.3 Bcf of

raw gas

Rich Gas Well Results:

90 day cumulative condensate

production of 58 Mbbls and 1.2

Bcf of raw gas

Diversified Natural Gas Market Access

10

Creating optionality through a portfolio approach to natural gas marketing

AECO NGTL Firm – 660 NGTL MMcf/d

Eastern CanadaTCPL Firm – 77 MMcf/d

US Mid-WestAlliance Firm – 508 MMcf/d

US Gulf CoastNGPL Firm – 100 MMcf/d

Source: ARC Financial

Note:

1) Volumes represent peak commitments by region over the next 5 years

2) Transportation commitments are not additive

• The Kakwa River Project is located in

close proximity to North America’s

largest source of condensate demand -

the Canadian oil sands

• More than 1 Bcf/d of firm service

transportation capacity to:

Alberta (AECO)

Eastern Canada (Dawn)

US Mid-West (Chicago Citygate)

Gulf Coast (Henry Hub)

US West (Malin)

• Other market access opportunities

projects being considered include:

Petrochemical manufacturing

LNG/LPG exports

Gas fired power generation

• Market Access

US WestGTN Firm – 92 MMcf/d

0

200

400

600

800

1,000

1,200

Q32017

Q42017

Q12018

Q22018

Q32018

Q42018

Q12019

Q22019

Q32019

Q42019

Q12020

Q22020

Q32020

Q42020

Vo

lum

e/C

ap

acit

y -

MM

cf/

d (

Ra

w G

as)

Alliance - Chicago NGPL - Henry Hub

NGTL - AECO TCPL - Dawn

GTN - Malin 7G Processing Capacity

Natural Gas Transportation and Processing

Firm transportation and processing capacity paving the way to profitable growth11

Firm Transportation Commitments and Processing Capacity

Assumptions:

(1) Alliance capacity is net of NGPL

(2) NGTL Capacity is net of TCPL Mainline and GTN

Innovative Infrastructure

To date 7G has invested over $1 billion in wholly-owned & operated infrastructure

• Super Pads:

Decentralized processing plants separating field condensate, gas and water

High pressure artificial gas lift at each well to assist lifting free liquids

Single phase gathering from pads boosts overall system capacity

Allow for half cycle growth once the pad is built as new wells come in on a ‘drill to fill’ basis

Modular design allows for the scalable development of the Kakwa River Project

7G currently has 9 super pads on production with 2 more under construction

• Processing Capacity:

• 510 MMcf/d of processing capacity in 2 wholly owned facilities with a 3rd plant expected online in 2018

• Access to 250 MMcf/d of third party processing capacity

• Total corporate processing capacity of 760 MMcf/d

• Condensate Handling:

• > 60,000 bbls/d of condensate stabilization capacity

12

The 7G Infrastructure Advantage

13

APPENDIX

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 thanequitable rights with other corporations, including those wholly owned by a person. We recognize that rights, sufficient to build andoperate an energy project, can be granted and taken away by society. Over the longer term, companies can only expect to thrive if theyserve the legitimate needs of society in which they exist. To thrive, companies must differentiate, rise above the pack, standout as beingamong the best with all of their stakeholders. At Seven Generations Energy Ltd., we acknowledge this granted entitlement and acceptfrom our stakeholders a duty to thrive and an understanding of the need to differentiate. Specifically, in acceptance of this challenge todifferentiate with all stakeholders, we acknowledge:

Only those who best serve their stakeholders can expect the support required to survive for the longer term.

The need of our business partners and infrastructure

customers to be treated fairly and attentively;

Level 1 Policy

14

The need of society for us to conduct our business in a

way that protects the natural beauty of the environment

and preserves the capacity of the earth to meet the needs

of present and future generations;

The need of Canada and Alberta for us to obey all

regulations and to proactively assist with the formulation

of new policy that enables our company and our industry

to better serve society;

The need of 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 shareholders and capital providers to have their investment managed responsibly

and ethically and to earn strong returns.

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 our employees to be compensated fairly and

provided a safe, healthy and happy work environment

including a healthy work life – outside life balance; and

Low GHGs 0.0127 carbon intensity(1)

GP Hospital $1.2 million raised

Safety first 0.56 TRIF in 2016

Responsible Development Highlights

15

• Second year in a row of reduced incident frequencies

• Building a culture of safety

• CDP Score of B

• 7G’s annual golf tournament has raised ~$1.2 million for the Grande Prairie Regional Hospital Foundation in its first four years

Safety Environment Community

(1) Represents estimated metric tonnes of carbon dioxide equivalent per barrel of oil equivalent of production. For additional information regarding the company’s estimated carbon intensity, please refer to the “Important

Notice” at the end of this presentation.

Upside Potential - Upper Montney Extension and Secondary Targets

16

(1) For illustrative purposes, not to scale.

Gross Acres Net AcresGross

SectionsNet Sections Average WI

167,360 121,120 262 189 72%

178,720 139,027 279 217 78%

178,720 139,027 279 217 78%

170,880 132,134 267 206 77%

169,760 137,357 265 215 81%

171,840 139,469 269 218 81%

167,680 135,955 262 212 81%

175,680 152,474 275 238 87%

172,800 149,594 270 234 87%

431,200 412,448 674 644 96%

435,360 415,590 680 649 95%

514,560 492,858 804 770 96%

Upper

Lower

Duvernay 290,560 285,549 454 446 98%

585,440 545,606 915 853 93%

(1) Totals are not additive due to overlapping rights.

*Commingling Potential

514,150 841 803 96%

TOTAL ACREAGE(1)

538,240

Cadomin*

Nikanassin

Nordegg

Charlie Lake*

Montney

Gething*

7G ACREAGE HELD BY ZONE (December 31, 2016)

Zone

Cardium

1WS

2WS

Dunvegan*

Cadotte*

Falher*

Wilrich

7G’s Infrastructure Access

17

Significant infrastructure investments to facilitate profitable full field development

Completion Optimization:Impact of Higher Intensity Completion and Frac Fluid

19

Higher Intensity Completion Slickwater vs. Nitrified Foam

$14.43$15.39

$11.17 $11.50

$14.26

$16.05

$10.97$11.68

$0.00

$2.00

$4.00

$6.00

$8.00

$10.00

$12.00

$14.00

$16.00

$18.00

F&D FD&A F&D FD&A

1P 2P

3 Yr Avg.

Dec. 31, 2016

Reserves & Resources

19

Note: The information shown on this slide is based upon the reports prepared by McDaniel, the Company’s independent qualified reserves evaluator, evaluating the Company’s reserves, contingent resources and prospective

resources, as at the effective dates that are shown above. The evaluated contingent resources that are reflected herein have been classified as “development pending” and are considered to have the highest chance of

commerciality of all resources other than reserves. For important information regarding the Company’s independently evaluated reserves, contingent resources and prospective resources and the F&D costs and FD&A costs

that have been calculated by the Company, please refer to the “Important Notice” that appears at the end of this presentation.

Reserves booked to 22% of land with significant resource potential

Year End 2P Reserves (MMBoe) 1P & 2P Finding Costs ($/Boe)

182283

789859

1,535

0

200

400

600

800

1,000

1,200

1,400

1,600

1,800

2012 2013 2014 2015 2016

Natural Gas

Liquids

December 31, 2016 December 31, 2015 ∆YoY

Category MMBoe % Liquids NPV10 ($MM) MMBoe % Liquids NPV10 ($MM) MMBoe NPV10 ($MM)

PDP 166 53% $1,991 73 55% $878 127% 127%

1P 825 54% $5,146 424 52% $2,937 95% 75%

2P 1,535 53% $9,996 859 52% $6,507 79% 54%

Best Estimate Contingent – Risked 1,391 44% $3,068 771 45% $2,790 80% 10%

Best Estimate Prospective – Risked 787 47% $723 418 46% $1,071 88% -32%

1.5X 1.4X

2.6X

2.9X

2.3X

1.3X

1.7X 1.7X

1.5X

1.7X

0.0X

0.5X

1.0X

1.5X

2.0X

2.5X

3.0X

3.5X

Q1 2015 Q2 2015 Q3 2015 Q4 2015 Q1 2016 Q2 2016 Q3 2016 Q4 2016 Q1 2017 Q2 2017

Prudent Balance Sheet Management

20

Conservative Financial Management

• Q2 2017 Net Debt to annualized

quarterly funds flow of 1.7X

o Annualized H1 2017 cash flow >$1.0

billion

• US$1.575 MM of senior notes

o US$700 MM 8.25% due May 2020

o US$425 MM 6.75% due May 2023

o US$450 MM 6.875% due June 2023

• Disciplined & mechanic commodity

risk management program

o Natural gas and condensate volumes

hedged out on a rolling 3-year basis

7G Net Debt to Quarterly Annualized Funds From Operations

Note: For additional information see “Non-IFRS Measures Advisory” in

the “Important Notice” that appears at the end of the presentation.

7G Hedged Volumes (BOE/d)

1) Average annual hedging volumes as at June 30, 2017.

2) Hedging interest coverage calculated as swap and long put prices multiplied by annual hedged volumes divided by 7G’s note

coupon payments converted into CAD.

1) Ratio calculated with quarter-end net debt divided by funds from operations for the same quarter multiplied by four.

5.5X 5.6X

3.3X

0.0X

1.0X

2.0X

3.0X

4.0X

5.0X

6.0X

0

10,000

20,000

30,000

40,000

50,000

60,000

70,000

ROY 2017 2018 2019

Hedgin

g I

nte

rest C

overa

ge R

atio

BO

E/d

Oil - CAD$ WTI Gas - Chicago CG Gas - AECO 7A Hedging Interest Coverage

Current Hedge Position

21

Q3 2017 Q4 2017 2017 Q1 2018 Q2 2018 Q3 2018 Q4 2018 2018 Q1 2019 Q2 2019 Q3 2019 Q4 2019 2019 Q1 2020 Q2 2020 Q3 2020 2020

Liquids Hedging

WTI Hedged - bbl/d 24,000 24,000 24,000 28,000 28,000 27,000 26,000 27,250 26,000 21,000 17,000 11,000 18,750 7,000 5,000 3,000 5,000

Average Bought Put (Floor) - CAD/bbl $61.21 $61.21 $61.21 $60.14 $60.14 $58.52 $58.27 $59.29 $58.27 $58.10 $58.53 $58.64 $58.33 $57.86 $57.00 $55.00 $57.00

Average Sold Call (Ceiling) - CAD/bbl $77.18 $77.18 $77.18 $76.76 $76.76 $77.33 $77.38 $77.05 $77.38 $77.20 $77.89 $77.10 $77.40 $74.77 $72.70 $70.65 $73.26

WTI Puts Sold - bbl/d* 9,000 9,000 9,000 12,000 12,000 12,000 12,000 12,000 12,000 10,000 6,000 2,000 7,500 2,000 2,000 2,000 2,000

Average Sold Put - CAD/bbl* $41.11 $41.11 $41.11 $40.83 $40.83 $40.83 $40.83 $40.83 $40.83 $41.00 $41.67 $40.00 $41.00 $40.00 $40.00 $40.00 $40.00

Gas Hedging

Total Gas Hedged - MMbtu/d 227,391 256,869 242,130 237,391 207,391 207,391 197,391 212,391 157,391 147,391 117,391 107,391 132,391 30,000 20,000 0 16,667

Gas Hedged - AECO - GJ/d 50,000 60,000 55,000 50,000 50,000 50,000 50,000 50,000 50,000 50,000 50,000 50,000 50,000 0 0 0 0

Average AECO Bought Put (Floor) - CAD/GJ $2.50 $2.50 $2.50 $2.50 $2.50 $2.50 $2.50 $2.50 $2.50 $2.50 $2.50 $2.50 $2.50 $0.00 $0.00 $0.00 n/a

Average AECO Sold Call (Ceiling) - CAD/GJ $3.04 $3.03 $3.03 $2.99 $2.99 $2.99 $2.99 $2.99 $2.99 $2.99 $2.99 $2.99 $2.99 $0.00 $0.00 $0.00 n/a

Gas Hedged - Chi CG - MMbtu/d 180,000 200,000 190,000 190,000 160,000 160,000 150,000 165,000 110,000 100,000 70,000 60,000 85,000 30,000 20,000 0 16,667

Average Chi CG Swap - USD/MMbtu $2.98 $2.97 $2.98 $2.92 $2.89 $2.89 $2.89 $2.90 $2.90 $2.90 $2.88 $2.86 $2.89 $2.79 $2.74 $0.00 $2.77

Average Swap - CAD/MMbtu** $3.92 $3.91 $3.91 $3.87 $3.85 $3.84 $3.83 $3.85 $3.79 $3.79 $3.77 $3.77 $3.79 $3.64 $3.56 $0.00 $3.61

FX Hedging

USD Notional Hedged (MM) $49.37 $54.65 $104.02 $49.95 $42.15 $42.60 $39.82 $174.51 $28.71 $26.38 $18.52 $15.80 $89.41 $7.61 $4.99 $0.00 $12.60

Average Rate 1.3151$ 1.3157$ 1.3154$ 1.3240$ 1.3288$ 1.3260$ 1.3277$ 1.3265$ 1.3084$ 1.3088$ 1.3128$ 1.3158$ 1.3107$ 1.3079$ 1.2978$ n/a 1.3039$

*Represents volumes and prices for additional puts sold for 3-way CAD WTI collars

**Chi CG converted to CAD/MMbtu @ average CAD/USD hedge rate

2020

Hedge Position

August 30, 2017

ROY 2017 2018 2019

Selected Financial and Operational Information

1) Certain prior period figures have been re-classified to conform with current period presentation

2) Figure is a non IFRS financial measure. Refer to the Company's Q2 2017 MD&A as filed on SEDAR for additional information. 22

VII - Recent Quarterly Results

OPERATING Q2 2017 Q1 2017 Q4 2016 Q3 2016 Q2 2016 Q1 2016 YE 2016 YE 2015

Average daily production

Condensate & oil (mbbls/d) 54.2 46.8 43.2 46.5 38.8 28.4 39.3 21.2

NGLs (mbbls/d) 42.8 42.2 33.4 33.8 30.2 22.6 30.0 14.3

Natural gas (MMcf/d) 409.6 384.0 334.0 314.0 290.0 225.0 291 149

Total (mboe/d) 165.2 153.1 132.3 132.6 117.4 88.5 117.8 60.4

CGR Ratio (bbls/MMcf) 132 122 129 148 134 126 135 142

LGR Ratio (bbls/MMcf) 104 110 100 108 104 100 103 96

Realized prices

Condensate & oil (C$/bbl) 58.57 64.07 56.96 49.93 52.05 39.92 50.59 50.84

NGLs (C$/bbl) 16.45 18.03 18.23 11.23 12.49 8.96 13.08 10.34

Natural gas (C$/mcf) 4.09 4.36 4.15 3.92 2.62 3.24 3.53 2.65

FINANCIAL

Condensate & oil revenues ($MM) 288.6 270.1 226.4 213.4 185.0 102.0 726.8 393.7

NGLs revenues ($MM) 64.1 68.5 56.1 35.0 33.4 19.4 143.9 52.8

Natural gas revenues ($MM) 152.4 150.8 127.3 113.3 69.0 66.6 376.2 145.4

Total revenues ($MM) 505.1 489.4 409.8 361.7 287.4 188.0 1,246.9 591.9

Royalties ($MM) (9.3) (16.8) (11.9) (0.4) 18.6 (13.0) (6.7) (57.9)

Operating expense ($MM) (93.9) (68.8) (59.1) (47.0) (44.8) (31.0) (181.9) (101.2)

Transportation expense (1) ($MM) (82.3) (72.0) (72.0) (74.7) (56.2) (35.7) (238.6) (59.0)

Netback prior to hedging(2) ($MM) 319.6 331.7 266.8 239.6 205.0 108.4 819.7 373.8

Realized hedging gain (loss) ($MM) 1.8 (7.2) 5.8 19.2 29.6 36.3 90.8 150.6

Netback after hedging(2) ($MM) 321.4 324.5 272.5 258.8 234.5 144.6 910.5 524.4

General and administrative expense ($MM) (12.3) (10.9) (10.8) (14.7) (10.0) (8.0) (43.5) (24.3)

Interest, processing and other ($MM) (41.0) (41.4) (42.0) (39.4) (27.1) (26.0) (134.4) (85.4)

Funds from operations (2) ($MM) 268.1 272.3 219.7 204.7 197.5 110.6 732.6 414.6

Netbacks

Oil and natural gas revenue ($/boe) 33.60 35.52 33.67 29.65 26.91 23.34 28.92 26.84

Royalties ($/boe) (0.62) (1.22) (0.98) (0.03) 1.74 (1.61) (0.16) (2.63)

Operating expense ($/boe) (6.24) (4.99) (4.86) (3.85) (4.20) (3.85) (4.22) (4.59)

Transportation and processing expense (1) ($/boe) (5.47) (5.22) (5.92) (6.12) (5.26) (4.43) (5.53) (2.68)

Operating netback prior to hedging ($/boe) 21.27 24.09 21.91 19.65 19.19 13.45 19.01 16.94

Realized hedging gain (loss) ($/boe) 0.12 (0.52) 0.48 1.57 2.77 4.50 2.11 6.83

Operating netback(2) ($/boe) 21.39 23.57 22.39 21.22 21.96 17.95 21.12 23.77

General and administrative expense ($/boe) (0.82) (0.79) (1.18) (1.21) (0.93) (0.99) (1.09) (1.10)

Interest, processing and other ($/boe) (2.73) (3.03) (3.18) (3.71) (2.59) (3.23) (4.14) (3.87)

Funds flow netback(2) ($/boe) 17.84 19.75 18.03 16.30 18.44 13.73 15.89 18.80

Capital investments

Land ($MM) 0.4 0.2 0.6 0.3 0.2 0.2 1.3 5.1

Drilling and completions ($MM) 342.3 259.8 186.6 133.7 125.0 152.5 597.8 813.8

Facilities and equipment ($MM) 153.9 87.1 78.5 62.6 88.1 108.0 337.2 478.0

Other ($MM) 15.9 15.2 18.0 11.1 6.0 6.5 41.6 12.1

Total capital investments(1) ($MM) 512.5 362.3 283.7 207.7 219.3 267.2 977.9 1,309.0

1) Price Assumptions: $50 US/bbl WTI, $3.00 US/MMBtu NYMEX HH and 0.77 USD/CAD FX. NGLs as % of WTI: C3 35%, C4 50%, C5 90%. Chicago gas discount $0.01 to NYMEX HH. Unit transportation costs: sales gas US$0.92/Mcf. Recovered liquids: $5.80/bbl. Average opex (first 3 years) = ~3.70

$/boe for sweet gas, ~$6.00 for sour gas (Wapiti Curve only). ~15% raw gas shrink. Fixed well operating cost = $20,000/mo. for half cycle, $30,000/mo. for full cycle.

2) Recoveries: NGL recoveries are based on a best estimate of the liquids to be extracted at 7G’s wholly owned plants in Alberta and the liquids to be processed by Aux Sable at its facilities near Chicago, Illinois pursuant to the terms of the rich gas premium agreement between 7G and Aux Sable, which

depends upon an assumed heating value and has been assumed to extend for the entire productive life of the wells. The Wapiti & Rich Gas Type Curve is based upon the type-curve that was used by McDaniel in its report dated March 7, 2017 evaluating 7G’s reserves as at December 31, 2016.

3) Other Type-curve Assumptions: For a description of the assumptions that have been made by the company in preparing its type-curves and in determining the estimated number of potential drilling opportunities, and for important additional information about the company’s type-curve forecasts and

estimates of potential drilling opportunities, please refer to the “Important Notice” at the end of this presentation.

4) Half-Cycle economics: Includes only the cost to drill, complete, tie, and equip well. Does not include all costs for Super Pad infrastructure, central processing, regional gathering, condensate stabilization, other infrastructure, land acquisition, corporate overhead (G&A), financing or corporate taxes. These

economics are intended to represent the marginal return of a single well investment on an existing Super Pad. No adjustments have been made for downtime or facility constraints.

5) Full-cycle economics: Include a $4.10/boe burden to carry infrastructure costs including central plant processing (NGL extraction), Super Pad build, regional gathering and sales pipelines and condensate stabilization. A $0.90/boe burden to carry corporate overhead (G&A). Land acquisition, financing costs

and corporate taxes have been excluded. Sunk investments to test, demonstrate, delineate and commercialize plays has also been excluded; the period of time (and related capital carrying costs) required to acquire, test and delineate the lands prior to commercial development has not been factored into

this analysis. It assumes a forward-looking development with existing knowledge of the risk profile of 7G’s Nest lands, including but not limited to reservoir deliverability, liquid-gas ratios, H2S content, gas and liquids compositions, and also assumes available pipeline transportation capacity with firm gas and

liquids transportation.

Note: For important supplemental information please refer to the “Important Notice” at the end of this presentation.

Individual Well EconomicsAssumes: US$50/bbl WTI, US$3.00/MMbtu NYMEX, $0.77 USD/CAD

23

2015 Type

Curve

2016 Type

Curve

2017 program

(high intensity)

Nest 2 Nest 2 Nest 2Nest 1 (2014

Prospectus)

Wapiti & Rich

Gas

INDIVIDUAL WELL ECONOMICS

(%) 98% 138% 184% 41% 44%

($MM) $13.6 $17.1 $19.4 $5.5 $4.6

(US$/MMBTU) $0.24 -$0.22 -$0.33 $1.47 $2.17

(%) 52% 77% 103% 18% 12%

($MM) $7.3 $10.1 $11.6 $1.5 $0.3

(US$/MMBTU) $1.70 $1.23 $1.11 $3.19 $3.36

WELL ASSUMPTIONS

Lateral length (m) 2,450 2,700 2,700 2,200 2,200

Stage count (#) 28 28 36 28 20

Tonnage (Tonnes/stage) 120 160 160 120 100

C* value ($MM) $14.3 $16.6 $18.9 $14.1 $11.7

Well cost (drill & complete) ($MM) $10.0 $10.0 $11.3 $8.5 $7.0

Well cost (tie & equip) ($MM) $1.0 $1.0 $1.0 $1.0 $1.0

Total well cost (DCET) ($MM) $11.0 $11.0 $12.3 $9.5 $8.0

Condensate gas ratio (bbls/MMcf) 118 118 118 135 56

Condensate production (bbls/d) 491 564 714 316 239

NGL production (bbls/d) 287 330 422 141 120

Raw gas production (mcf/d) 3,984 4,573 5,855 2,232 3,862

Condensate recovery (mbbls) 468 510 510 325 248

NGL recovery (C2-C4) (mbbls) 502 548 548 309 163

Natural gas recovery (bcf) 5.9 6.4 6.4 4.1 4.7

Total EUR (mboe) 1,945 2,122 2,122 1,317 1,200

# 800 800 800 500 1,000Inventory of drilling locations

SENSITIVITIES - SPENDING FOCUS IN 2017

2017 program

(delineation & future

development)

Avera

ge 1

st

Year

EU

RIn

pu

ts

Half-Cycle IRR

Half-Cycle NPV10

Half-Cycle Supply cost (20% IRR)

Full-Cycle IRR

Full-Cycle NPV10

Full-Cycle Supply cost (20% IRR)

Individual Well Economics: IRR Sensitivities (half-cycle, pre-tax)

24

Assumptions:

- NGLs as % of WTI: C3 35%, C4 50%, C5 90%. Chicago gas discount $0.01 to NYMEX HH. Unit transportation costs: sales gas US$0.92/Mcf. Recovered liquids: $5.80/bbl. Average opex (first 3 years) = ~3.70 $/boe, ~15% raw gas shrink.

Fixed well operating cost = $20,000/mo. for half cycle economics. FX rate is on a sliding-scale based on WTI price used.

- Half-cycle economics: include only the cost to drill, complete, tie & equip a well. No costs for central processing, regional gathering, condensate stabilization, other infrastructure, land acquisition, corporate overhead (G&A), financing or

corporate taxes are included.

Drilling Cost & Efficiency Improvements

25

Drilling Days vs. Depth Drilling Cost vs. Depth

Potential to offset cost inflation through continued efficiency gains

m

1000 m

2000 m

3000 m

4000 m

5000 m

6000 m

7000 m

2011 First

MNTN Hz.

2012

2013v

2014v2015 -

Pacesetter

v

2015

2016 -

Pacesetter

m

1000 m

2000 m

3000 m

4000 m

5000 m

6000 m

7000 m

2011 First

MNTN Hz.

2012

2013

v2014v2015 -

Pacesetter

v2015

2016 -

Pacesetter

v

Well Results within the Nest

- Rates are raw gas and condensate field estimates as of July 1st, 2017 and are not normalized for lateral length

- Producing days only include days that wells had non-zero natural gas or condensate production

- Rates reflect historical results of wells drilled by 7G and excludes wells acquired as part of the significant acquisition that was completed in 2016

Nest 2

Gas C5+ Total C5 +Yield Wells

Mcf/d bbls/d boe/d bbl/MMcf (#)

IP30 4,498 935 1,684 208 195

IP90 4,343 825 1,548 190 174

IP180 3,986 654 1,318 164 158

IP270 3,547 555 1,146 157 138

IP365 3,368 484 1,045 144 115

Nest 1

Gas C5+ Total C5 +Yield Wells

Mcf/d bbls/d boe/d bbl/MMcf (#)

IP30 2,315 651 1,036 281 15

IP90 2,287 501 882 220 15

IP180 2,177 397 760 182 15

IP270 2,038 339 678 166 15

IP365 1,917 296 616 155 15

26

Inventory of Nest 1 & Nest 2 Montney Wells

Nest 1 Drilling Phase Completion Phase Tie-in PhaseIn Progress Well

InventoryProducing Wells

Wells down due to

Concurrent Ops

October 1, 2015 0 1 0 1 15 0

January 1, 2016 0 0 0 0 15 0

April 1, 2016 0 0 0 0 15 0

July 1, 2016 0 0 0 0 15 0

Total Nest Drilling Phase Completion Phase Tie-in PhaseIn Progress Well

InventoryProducing Wells

Wells down due to

Concurrent Ops

October 1, 2016 24 32 0 56 203 5

January 1, 2017 43 40 1 84 210 8

April 1, 2017 38 38 2 78 228 7

July 1, 2017 24 49 0 73 238 19

*Well activity shown includes only Upper/Middle Montney wells in the Nest Area.

27

Nest 1 Drilling Phase Completion Phase Tie-in PhaseIn Progress Well

InventoryProducing Wells

Wells down due to

Concurrent Ops

October 1, 2016 0 0 0 0 15 0

January 1, 2017 0 0 0 0 15 0

April 1, 2017 0 1 0 1 18 0

July 1, 2017 1 1 0 2 18 0

Nest 2 Drilling Phase Completion Phase Tie-in PhaseIn Progress Well

InventoryProducing Wells

Wells down due to

Concurrent Ops

October 1, 2016 24 32 0 56 188 5

January 1, 2017 43 40 1 84 195 8

April 1, 2017 38 37 2 77 210 7

July 1, 2017 23 48 0 71 220 19

Sweet Spot of the Montney

Sources: Canadian Discovery Ltd. & Graham Davies Geological Consultants Ltd. (2008, 2011), & Steven Burnie (2011), BC Ministry of Energy & Mines, Alberta Geological Survey (modified by RBC & 7G) Lands as of 4/30/17

• Thickness→ Large Resources in Place

• Over Pressured→ High Productivity • Brittle Rock→ High Recovery Factor

28

Lower Temperature→ High Liquids Content

Important Notice

General Advisory

The information contained in this presentation does not purport to be all-

inclusive or contain all information that readers may require. Prospective

investors are encouraged to conduct their own analysis and review of Seven

Generations Energy Ltd. (“Seven Generations”, “7G”, the “company” or the

“Company”) and of the information contained in this presentation. Without

limitation, prospective investors should read the entire record of publicly filed

documents relating to the Company, consider the advice of their financial,

legal, accounting, tax and other professional advisors and such other factors

they consider appropriate in investigating and analyzing the Company. An

investor should rely only on the information provided by the Company and is

not entitled to rely on parts of that information to the exclusion of others. The

Company has not authorized anyone to provide investors with additional or

different information, and any such information, including statements in media

articles about Seven Generations, should not be relied upon. In this

presentation, unless otherwise indicated, all dollar amounts are expressed in

Canadian dollars.

An investment in the securities of Seven Generations is speculative and

involves a high degree of risk that should be considered by potential investors.

Seven Generations’ business is subject to the risks normally encountered in

the oil and gas industry and, more specifically, the shale and tight liquids-rich

natural gas sector of the oil and natural gas industry, and certain other risks

that are associated with Seven Generations’ stage of development. An

investment in the Company’s securities is suitable only for those purchasers

who are willing to risk a loss of some or all of their investment and who can

afford to lose some or all of their investment.

Non-IFRS Measures Advisory

In addition to using financial measures prescribed by International Financial

Reporting Standards (“IFRS”), references are made in this presentation to

“netbacks”, “operating netback”, “available funding”, “funds from operations”,

“funds flow per sshare”, “adjusted working capital”, “net debt”, “adjusted

earnings before interest, taxes, depreciation and amortization” or “adjusted

EBITDA”, “FactSet EBITDA” and “cash return on invested capital” or “CROIC”,

which are measures that do not have any standardized meaning as prescribed

by IFRS. Accordingly, the Company’s use of such terms may not be

comparable to similarly defined measures presented by other entities and

comparisons should not be made between such measures provided by the

Company and by other companies without also taking into account any

differences in the way that the calculations were prepared. For further details

about “operating netback”, “net debt”, “available funding”, “funds from

operations”, “adjusted working capital” and “adjusted EBITDA” see “Non-IFRS

Financial Measures” in the Company’s Management’s Discussion and

Analysis for three months ended March 31, 2017, which is available on the

SEDAR website at www.sedar.com.

“Adjusted EBITDA” as defined and calculated in the company’s Management

Discussion and Analysis is based on the covenant calculation in the

company’s credit facility. :”FactSet EBITDA” is calculated by a third party and

differs from adjusted EBITDA primarily through the exclusion of realized

hedging gains and losses.

Cash return on invested capital (“CROIC”) is FactSet EBITDA divided by the

average unamortized cost of developed and producing oil and natural gas

assets and is a performance measure of a company’s ability to generate

returns on capital investments. The 2016 CROIC of 15% reflects FactSet

EBITDA of $757.9 million divided by the average cost of oil and natural gas

assets of $5,104.6 million. The 2015 CROIC of 12% reflects FactSet EBITDA

of $334.2 million divided by the average cost of oil and natural gas assets of

$2,769.9 million.

Forward-Looking Information Advisory

This presentation contains certain forward-looking information and statements

that involve various risks, uncertainties and other factors. The use of any of

the words “anticipate”, “continue”, “estimate”, “expect”, “may”, “will”, “should”,

“believe”, “plans”, and similar expressions are intended to identify forward-

looking information or statements. In particular, but without limiting the

foregoing, this presentation contains forward-looking information and

statements pertaining to the following: the Company’s objectives, strategies

and competitive strengths; the ability to earn full cycle returns on capital

employed; the ability to leverage market access to capture premium markets;

ability to remain among North America’s lowest supply-cost gas developers;

expected production, profitable production growth and estimated quarterly

production per share; rig counts; anticipated liquids yields; well counts; the

Company’s planned capital investments and allocation of capital; ability to

optimize capital efficiencies and continuously improve returns on capital

invested; type curves; forecasted decline rates; cumulative production

expected based upon the utilization of certain specified completion designs;

estimated number of undeveloped drilling opportunities or drilling locations;

estimated recoveries; expectation that there are decades of drilling

opportunities in the Company’s Montney assets; anticipated drilling and

completion costs, facilities costs, and other costs in 2017; market access

options; forecasted half-cycle and full-cycle economics, including forecasted

NPVs, IRRs, price sensitivities and break-even prices; estimated future costs,

supply costs, cost reductions and cost performance; forecasted well

economics; planned development activities; resource potential from various

areas and formations within 7G’s development properties; ability to

commercialize assets outside of the Company’s Nest area; transportation and

processing capacity; expectation that the Company will have a new natural

gas processing plant online in 2018; future upside potential of the Deep SW

area, the Wapiti area, the Rich Gas area and shallower targets within the

Company’s properties; management’s estimation that there is significant

unverified resource in the Deep SW area, the Lower Montney formation and

Cretaceous formation; ability to continuously improve returns on capital

invested; estimated condensate demand in Alberta; and pressure, thickness,

geology and temperature estimates in the Montney formation. In addition,

references to reserves and resources are deemed to be forward-looking

information, as they involve the implied assessment, based on certain

estimates and assumptions, that the reserves and resources described exist in

the quantities predicted or estimated.

With respect to forward-looking information contained in this presentation,

assumptions have been made, regarding, among other things: that wells

drilled in the same fashion in the same formations in proximity to the type-

wells that were used in 7G’s type-curve forecasts will deliver similar production

results, including liquids yields; future oil, natural gas liquids and natural gas

prices; the Company’s ability to obtain qualified staff and equipment in a

timely and cost efficient manner; the Company’s ability to market production of

oil, NGLs and natural gas successfully to customers; the Company’s future

production levels; the applicability of technologies for the Company’s reserves;

future capital investments by the Company; future cash flows from production;

future sources of funding for the Company’s capital program; the Company’s

future debt levels; geological and engineering estimates in respect of the

Company’s reserves and resources estimates; the Company’s production

growth will be sufficient to meet firm transportation and processing capacity;

the geography of the areas in which the Company is conducting exploration

and development activities, and the access, economic and physical limitations

to which the Company may be subject from time to time; the impact of

competition; the regulatory framework governing royalties, taxes,

environmental and operational matters in the jurisdictions in which the

Company conducts its business and any other jurisdictions in which the

Company may conduct its business in the future; and the Company’s ability to

obtain financing on acceptable terms.

Assumptions made in the calculation of forecasted half-cycle and full-cycle

economics, including forecasted NPVs, IRRs, price sensitivities, commodity

prices and recovery factors, and the assumptions made in the preparation of

type-curves, are provided in footnotes proximate to those disclosures. An

assumption has also been made that further well delineation activities will

confirm management’s estimates regarding reservoir quality of its properties

that fall outside of the Company’s core development areas. With respect to

the estimated number of drilling locations or potential drilling opportunities that

are referenced herein, various assumptions have been made. These

assumptions are described under the heading “Note Regarding Potential

Drilling Opportunities” below.

32

Important Notice

(cont. from previous slide) Actual results could differ materially from those

anticipated in forward-looking information as a result of the risks and risk

factors that are set forth in the Company’s Annual Information Form dated

March 7, 2017 (the “AIF”), which is available on SEDAR at www.sedar.com,

including, but not limited to: the possibility of failure to realize the anticipated

benefits from the significant asset acquisition that was completed in 2016;

volatility in market prices and demand for oil, NGLs and natural gas, and

hedging activities related thereto; general economic, business and industry

conditions; variance of the Company’s actual capital costs, operating costs

and economic returns from those anticipated; the ability to find, develop or

acquire additional reserves and the availability of the capital or financing

necessary to do so on satisfactory terms; risks related to the exploration,

development and production of oil and natural gas reserves and resources;

negative public perception of oil sands development, oil and natural gas

development and transportation, hydraulic fracturing and fossil fuels; actions

by governmental authorities, including changes in government regulation,

royalties and taxation; the rescission, or amendment to the conditions of,

groundwater licenses of the Company; management of the Company’s

growth; the ability to successfully identify and make attractive acquisitions,

joint ventures or investments, or successfully integrate future acquisitions or

businesses; the availability, cost or shortage of rigs, equipment, raw materials,

supplies or qualified personnel; adoption or modification of climate change

legislation by governments; the absence or loss of key employees; uncertainty

associated with estimates of oil, NGLs and natural gas reserves and resources

and the variance of such estimates from actual future production; dependence

upon compressors, gathering lines, pipelines and other facilities, certain of

which the Company does not control; the ability to satisfy obligations under

the Company’s firm commitment transportation arrangements; the

uncertainties related to the Company’s identified drilling locations; the high-

risk nature of successfully stimulating well productivity and drilling for and

producing oil, NGLs and natural gas; operating hazards and uninsured risks;

risk of fires, floods and natural disasters; the possibility that the Company’s

drilling activities may encounter sour gas; execution risks associated with the

Company’s business plan; failure to acquire or develop replacement reserves;

the concentration of the Company’s assets in the Kakwa River Project area;

unforeseen title defects; aboriginal claims; failure to accurately estimate

abandonment and reclamation costs; development and exploratory drilling

efforts and well operations may not be profitable or achieve the targeted

return; horizontal drilling and completion technique risks and failure of drilling

results to meet expectations for reserves or production; limited intellectual

property protection for operating practices and dependence on employees and

contractors; third-party claims regarding the Company’s right to use

technology and equipment; expiry of certain leases for the undeveloped

leasehold acreage in the near future; failure to realize the anticipated benefits

of acquisitions or dispositions; failure of properties acquired now or in the

future to produce as projected and inability to determine reserve and resource

potential, identify liabilities associated with acquired properties or obtain

protection from sellers against such liabilities; changes in the application,

interpretation and enforcement of applicable laws and regulations; restrictions

on drilling intended to protect certain species of wildlife; potential conflicts of

interests; actual results differing materially from management estimates and

assumptions; seasonality of the Company’s activities and the Canadian oil and

gas industry; alternatives to and changing demand for petroleum products;

extensive competition in the Company’s industry; changes in the Company’s

credit ratings; dependence upon a limited number of customers; lower oil,

NGLs and natural gas prices and higher costs; failure of 2D and 3D seismic

data used by the Company to accurately identify the presence of oil and

natural gas; risks relating to commodity price hedging instruments; terrorist

attacks or armed conflict; cyber security risks, loss of information and

computer systems; inability to dispose of non-strategic assets on attractive

terms; security deposits required under provincial liability management

programs; reassessment by taxing authorities of the Company’s prior

transactions and filings; variations in foreign exchange rates and interest

rates; third-party credit risk including risk associated with counterparties in risk

management activities related to commodity prices and foreign exchange

rates; sufficiency of insurance policies; potential litigation; variation in future

calculations of non-IFRS measures; sufficiency of internal controls; breach of

agreements by counterparties and potential enforceability issues in contracts;

impact of expansion into new activities on risk exposure; inability of the

Company to respond quickly to competitive pressures; and the risks related to

the common Shares that are publicly traded and the Company’s senior notes

and other indebtedness, including the potential inability to comply with the

covenants in the credit agreement related to the Company’s credit facilities

and/or the covenants in the indentures in respect of the Company’s senior

unsecured notes.

Financial outlook and future-oriented financial information contained in this

presentation regarding prospective financial performance, financial position,

cash flows or well economics is based on assumptions about future events,

including economic conditions and proposed courses of action, based on

management’s assessment of the relevant information that is currently

available. Projected operational information also contains forward-looking

information and is based on a number of material assumptions and factors, as

are set out herein. Such projections may also be considered to contain future

oriented financial information or a financial outlook. The actual results of the

Company’s operations for any period will likely vary from the amounts set forth

in these projections, and such variations may be material. Actual results will

vary from projected results. Readers are cautioned that any such financial

outlook and future-oriented financial information contained herein should not

be used for purposes other than those for which it is disclosed herein.

The forward-looking statements included in this presentation are expressly

qualified by the foregoing cautionary statements and are made as of the date

of this presentation. The Company does not undertake any obligation to

publicly update or revise any forward-looking statements except as required by

applicable securities laws. No assurance can be given that these expectations

will prove to be correct and such forward-looking statements included in this

presentation should not be unduly relied upon. Certain information contained

herein has been prepared by third-party sources (and is identified as such)

and has not been independently audited or verified by the Company.

Presentation of Oil and Gas Information

Estimates of the Company’s reserves, contingent resources and prospective

resources and the net present value of future net revenue attributable to the

Company’s reserves, contingent resources and prospective resources are

based upon the reports prepared by McDaniel & Associates Consultants Ltd.

(“McDaniel”), the Company’s independent qualified reserves evaluator, as at

the effective dates that are specified in this presentation. The estimates of

reserves, contingent resources and prospective resources provided in this

presentation are estimates only and there is no guarantee that the estimated

reserves, contingent resources and prospective resources will be recovered.

Actual reserves, contingent resources and prospective resources may be

greater than or less than the estimates provided in this in this presentation and

the differences may be material. Estimates of net present value of future net

revenue attributable to the Company’s reserves, contingent resources and

prospective resources do not represent fair market value and there is

uncertainty that the net present value of future net revenue will be realized.

There is no assurance that the forecast price and cost assumptions applied by

McDaniel in evaluating Seven Generations’ reserves, contingent resources

and prospective resources will be attained and variances could be material.

There is no certainty that any portion of the prospective resources will be

discovered. If discovered, there is no certainty that it will be commercially

viable to produce any portion of the prospective resources. There is also

uncertainty that it will be commercially viable to produce any part of the

contingent resources. Estimates of net present value of future net revenue

from contingent resources and prospective resources are preliminary in nature

and are provided to assist the reader in reaching an opinion on the merit and

likelihood of the Company proceeding with the required investment. Such

estimates include contingent resources and prospective resources that are

considered too uncertain with respect to the chance of development and

chance of discovery to be classified as reserves. Readers should refer to the

AIF for a discussion of the significant factors relevant to the estimates of

prospective resources and contingent resources, a description of the Kakwa

River Project, including estimated costs and timelines and the specific

contingencies which prevent the classification of the Company’s contingent

resources as reserves.

This presentation includes estimates of contingent resources and prospective

resources, as at December 31, 2015 and December 31, 2016, that have been

risked by McDaniel for the probability of loss or failure in accordance with the

COGE Handbook. For contingent resources, the risk component relating to the

likelihood that an accumulation will be commercially developed is referred to

as the chance of development. For contingent resources the chance of

commerciality is equal to the chance of development. The contingent

resources evaluated by McDaniel, as at December 31, 2015 and December

31, 2016, were classified in the “development pending” project maturity sub-

class and are considered to have the highest chance of commerciality of all

resources other than reserves. In its December 31, 2015 and December 31,

2016 evaluations, McDaniel evaluated the risks and contingencies that were

relevant to the contingent resources, as are described in the AIF, and

determined that a 95% chance of development was appropriate for the

contingent resources that were assigned to the development pending project

maturity sub-class. The risked contingent resource volumes and associated

net present value, as at December 31, 2015 and December 31, 2016 were

determined by multiplying the un-risked volumes and values by the associated

chance of development that was estimated by McDaniel (i.e. 95%).

Prospective resources have both an associated chance of discovery and a

chance of development. Not all exploration projects will result in discoveries.

The chance that an exploration project will result in the discovery of petroleum

is referred to as the chance of discovery.

33

Important Notice

(cont. from previous slide) Thus, for an undiscovered accumulation, the

chance of commerciality is the product of two risk components — the chance

of discovery and the chance of development. McDaniel has sub-classified the

prospective resources that were evaluated, as at December 31, 2015 and as

at December 31, 2016, by maturity status, consistent with the requirements of

the COGE Handbook. The prospective resources associated with the upper

Montney, as at December 31, 2015 and as at December 31, 2016, were sub-

classified as “prospect” and the prospective resources associated with the

lower Montney were sub-classified as “lead”. The evaluation of the risks and

the risking process relevant to the upper Montney prospective resources and

the lower Montney prospective resources as at December 31, 2016 are

described in the AIF, and the evaluation of the risks and the risking process

relevant to the upper Montney prospective resources and the lower Montney

prospective resources at December 31, 2015 are described in the annual

information form dated March 8, 2016 (the “2015 AIF”) that are available on

SEDAR at www.sedar.com

Risks that could impact the chance of discovery and chance of development

are described in the AIF and include: geological uncertainty and uncertainty

regarding individual well drainage areas; uncertainty regarding the consistency

of productivity that may be achieved from lands with attributed resources;

potential delays in development due to product prices, access to capital,

availability of markets and/or take-away capacity; and uncertainty regarding

potential flow rates from wells and the economics of those wells. Significant

factors that may change the prospective resources and contingent resources

estimates are described in the AIF and include further delineation drilling,

which could change the estimates either positively or negatively, future

technology improvements, which would positively affect the estimates, and

additional transportation and processing capacity that could affect the volumes

recoverable or type of production. Additional facility design work, development

plans, reservoir studies and delineation drilling is expected to be completed by

the Company in accordance with its long-term resource development plan.

The reserves and resources information contained in this presentation should

be reviewed in conjunction with the AIF and 2015 AIF, which contain

important additional information regarding the independent reserve, contingent

resource and prospective resource evaluations that were conducted by

McDaniel and a description of, and important information about, the reserves

and resources terms used in this presentation. The AIF and 2015 AIF are

available on the SEDAR website at www.sedar.com.

Note Regarding Oil and Gas Metrics

This presentation includes certain oil and gas metrics, including barrels of oil

equivalent (“boes”), operating netback, finding and development (“F&D”) costs

and finding, development acquisition (“FD&A”) costs, and carbon intensity,

which do not have standardized meanings or standard methods of calculation

and therefore such measures may not be comparable to similar measures

used by other companies and should not be used to make comparisons. Such

metrics have been included herein to provide readers with additional

information to evaluate the Company’s performance; however, such measures

are not reliable indicators of the future performance of the Company and

future performance may not compare to the performance in previous periods

and therefore such metrics should not be relied upon.

Seven Generations has adopted the standard of 6 Mcf:1 bbl when converting

natural gas to oil equivalent. Condensate and other NGLs are converted to oil

equivalent at a ratio of 1 bbl:1 bbl. Boes may be misleading, particularly if

used in isolation. A boe conversion ratio of 6 Mcf:1 bbl is based roughly on an

energy equivalency conversion method primarily applicable at the burner tip

and does not represent a value equivalency at 7G’s sales points. Given the

value ratio based on the current price of oil as compared to natural gas is

significantly different from the energy equivalency of 6 Mcf: 1 bbl, utilizing a

conversion ratio at 6 Mcf: 1 bbl may be misleading as an indication of value.

Operating netback is calculated on a per boe basis and is determined by

deducting royalties, operating and transportation expenses from oil and

natural gas revenue and, except where otherwise indicated, after adjusting for

realized hedging gains or losses. Operating netback is utilized by the

Company and others to better analyze the operating performance of its oil and

natural gas assets.

FD&A costs are calculated as the sum of exploration and development capital,

plus acquisition capital, plus changes in future development costs for the given

year, divided by total reserve additions for that year, based upon the

independent reserves evaluations that were conducted by McDaniel. F&D

costs are calculated as the sum of exploration and development costs, plus

changes in future development costs (excluding future development capital

associated with acquisitions and dispositions), divided by reserve additions

(excluding reserves added via acquisitions), based upon the independent

reserves evaluations that were conducted by McDaniel. Both F&D costs and

FD&A costs have been presented since acquisition and disposition activity can

result in reserve replacement metrics that are not indicative of the long-term

cost structure that is expected from the Company’s assets.

The carbon intensity estimate provided herein was calculated by 7G with the

assistance of third parties. 7G quantified and reported its greenhouse gas

(“GHG”) emissions using what is referred to as the “operational control”

approach. 7G’s deemed organizational boundary included its corporate offices

and all natural gas extraction and processing facilities (including well pads).

7G elected to report its Scope 1 and 2 GHG emissions and not to report its

Scope 3 GHG emissions. For the purposes 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 from stationary

equipment, mobile combustion, and process emissions and fugitive

emissions);

• 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.

Notably, 7G’s drilling and completion activities in the relevant period were

conducted by third parties and, consequently, those activities were deemed to

be Scope 3.

7G uses third parties to help quantify its GHG emissions. For the 2015

reporting year, Deloitte LLP was retained by Seven Generations to evaluate

GHG emissions from all major facilities located in Alberta (gas plants, gas

gathering systems and batteries) in accordance with Alberta’s Specified Gas

Emitters Regulation (“SGER”) reporting program, Alberta’s Specified Gas

Reporting Regulation, and Environment and Climate Change Canada’s

Greenhouse Gas Emissions Reporting Program, and to quantify 7G’s Scope 1

emissions for reporting purposes. To conduct this quantification, emission

calculation methods were taken from the approved reference sources listed in

the SGER guidance publication titled “Technical Guidance for Completing

Specified Gas Baseline Emission Intensity Applications”. Further quantification

of Scope 1 emissions and quantification Scope 2 emissions for reporting

purposes was conducted by DXD Consulting Inc. (“DXD”) using API 2009

guidance and emissions factors. The Carbon Disclosure Project’s (“CDP”)

CDP Climate Change 2016 Questionnaire was then prepared and filed by 7G

utilizing information that was provided by Deloitte LLP and DXD.

Note Regarding Type-Curves

The Nest 1 and Nest 2 type curves that have either been provided herein, or

have been used in connection with the forecasted economics and in

determining the estimated number of potential drilling opportunities that are

referred to in this presentation, have been estimated using a combination of a

statistical approaches to early-life production from 7G’s Nest 1 and Nest 2

wells, matched to volumetric estimates that are attributable to properties in the

Company’s Nest 1 and Nest 2 areas, based on known reservoir parameters.

Early-life statistics use data from the Company’s producing Nest 1 and Nest 2

wells, adjusted for stage count and lateral length on a producing rate versus

time basis, a cumulative volume versus time basis, and a producing rate

versus cumulative volume basis, to ensure a reasonable fit. The Company’s

historical drilling in its Nest 2 area has predominantly been in the upper and

middle intervals of the Montney formation with 77 wells providing the statistical

basis for anticipated future well results. The Company’s historical drilling in its

Nest 1 area has predominantly been in the upper and middle intervals of the

Montney formation, with 11 wells providing the statistical basis for anticipated

future well results.

In the report prepared by McDaniel dated March 7, 2017 evaluating the tight

oil, conventional natural gas, shale gas and NGL reserves attributable to

certain assets of Seven Generations as at December 31, 2016 (the “McDaniel

Reserves Report”), the report prepared by McDaniel dated March 7, 2017

evaluating the shale gas and NGL contingent resources attributable to certain

of the assets of Seven Generations as at December 31, 2016 (the “McDaniel

Contingent Resources Report”), and the report prepared by McDaniel dated

March 7, 2017 evaluating the shale gas and NGL prospective resources

attributable to certain of the assets of Seven Generations as at December 31,

2016 (the “McDaniel Prospective Resources Report”), McDaniel assigned

proved plus probable reserves to 78% of the Nest 2 sections evaluated; best

estimate contingent resources to 22% of the Nest 2 sections evaluated;

proved plus probable reserves to 50% of the Nest 1 sections evaluated; and

best estimate contingent resources to 50% of the Nest 1 sections evaluated.

The type-curve estimates in respect of the Wapiti & Rich Gas areas

referenced herein is almost identical to the type-curve that was used by

McDaniel in the preparation of the McDaniel Reserves Report, the McDaniel

Contingent Resources Report and the McDaniel Prospective Resources

Report. The Wapiti & Rich Gas type-curve uses a combination of statistical

approaches to early-life production from wells that were drilled by Seven

Generations’ competitors, matched to volumetric estimates that are

attributable to properties in the company’s Wapiti area based on expected

reservoir parameters. Early-life statistics use data from the type-wells,

adjusted for stage count and lateral length on a producing rate versus time

basis, a cumulative volume versus time basis, and a producing rate versus

cumulative volume basis, to ensure a reasonable fit. The type-wells are

located in the middle interval of the Montney formation, with 13 wells providing

the statistical basis for anticipated future well results.

34

Important Notice

(cont. from previous slide) Recoverable hydrocarbon calculations use

forecasted EUR factors applied to volumetric estimates and decline curves are

used to align early statistical results with the forecasted EURs. The EURs for

each type-curve area were estimated by qualified reserves evaluators from

Seven Generations based on estimated resources, the estimated number of

wells to be drilled in each section, estimated lateral well length and estimated

recovery factors. EURs do not have any standardized meaning and readers

are cautioned that the estimated EURs may not be comparable to EUR

estimates prepared by the company’s competitors. Actual EURs may vary

significantly from the company’s estimates.

The Company has opted to provide the type-curve forecasts that have been

prepared by qualified reserves evaluators from Seven Generations in this

document, rather than the type-curves that were prepared by McDaniel, since

the internally generated type-curves are what the company has used to

determine its production guidance, capital budget and development plans.

Note Regarding Potential Drilling Opportunities

The references to drilling locations or potential drilling opportunities that are

contained herein have been prepared by qualified reserves evaluators from

Seven Generations as at the date hereof. These estimates were prepared in

accordance with the standards set forth in the COGE Handbook.

Of the 800 potential drilling opportunities that are estimated to be contained

within in the company’s Nest 2 area: 72% were attributed proved plus

probable reserves in the McDaniel Reserves Report; 28% were attributed best

estimate contingent resources in the McDaniel Contingent Resources Report;

and 0% were attributed best estimate prospective resources in the McDaniel

Prospective Resources Report.

Of the 500 potential drilling opportunities that are estimated to be contained

within the company’s Nest 1 area: 46% were attributed proved plus probable

reserves in the McDaniel Reserves Report; 54% were attributed best estimate

contingent resources in the McDaniel Contingent Resources Report; and 0%

were attributed best estimate prospective resources in the McDaniel

Prospective Resources Report.

Of the 1,000 potential drilling opportunities that are estimated to be contained

within the company’s Wapiti & Rich Gas area: 8% were attributed proved plus

probable reserves in the McDaniel Reserves Report; 47% were attributed best

estimate contingent resources in the McDaniel Contingent Resources Report;

and 45% were attributed best estimate prospective resources in the McDaniel

Prospective Resources Report.

For the purposes of estimating potential drilling opportunities, the company

has assumed that natural gas production will be delivered through Alliance

Pipeline and that liquids will be extracted at 7G’s wholly-owned plants in

Alberta and also at Aux Sable’s facilities near Chicago, Illinois.

Oil and Gas Definitions

“best estimate” is a classification of estimated resources described in the

Canadian Oil and Gas Evaluation Handbook, which is considered to be the

best estimate of the quantity that will actually be recovered. It is equally likely

that the actual quantities recovered will be greater or less than the best

estimate. Resources in the best 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 the quantities of petroleum estimated, as of a

given date, to be potentially recoverable from known accumulations using

established technology or technology under development, but which are not

currently considered to be commercially recoverable due to one or more

contingencies. Contingencies are conditions that must be satisfied for a

portion of contingent resources to be classified as reserves that are: (a)

specific to the project being evaluated; and (b) expected to be resolved within

a reasonable timeframe. Contingencies may include factors such as

economic, legal, environmental, political and regulatory matters or a lack of

markets. It is also appropriate to classify as contingent resources the

estimated discovered recoverable quantities associated with a project in the

early evaluation stage.

“developed producing reserves” are those 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 be known

with reasonable certainty.

“developed reserves” are those reserves that are expected to be recovered

from existing wells and installed facilities or, if facilities have not been

installed, that would involve a low expenditure (for example, when compared

to the cost of drilling a well) to put the reserves on production. The developed

category may be subdivided into producing and non-producing.

“development pending” is a sub-classification of contingent resources

estimates based upon project maturity which is appropriate where resolution

of the final conditions for development is being actively pursued (high chance

of development).

“gross” means: (i) in relation to the Company’s interest in production,

reserves, contingent resources or prospective resources, its “company gross”

production, reserves, contingent resources or prospective resources, which

are the Company’s working interest (operating or non-operating) share before

deduction of royalties and without including any royalty interests of the

Company; (ii) in relation to wells, the total number of wells in which a company

has an interest; and (iii) in relation to properties, the total area of properties in

which the Company has an interest.

“lead” is a sub-classification of prospective resources estimates based upon

project maturity which is appropriate where a potential accumulation is within

a play requires more data acquisition and/or evaluation in order to be

classified as a prospect.

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

“net” means: (i) in relation to the Company’s interest in production or

reserves, the Company’s working interest (operating or non-operating) share

after deduction of royalty obligations, plus the Company’s royalty interest in

production or reserves; (ii) in relation to the Company’s interest in wells, the

number of wells obtained by aggregating the Company’s working interest in

each of its gross wells; and (iii) in relation to the Company’s interest in a

property, the total area in which the Company has an interest multiplied by the

working interest owned by the Company.

“probable reserves” are those additional reserves that are less certain to be

recovered than proved reserves. It is equally likely that the actual remaining

quantities recovered will be greater or less than the sum of the estimated

proved plus probable reserves.

“prospect” is a sub-classification of prospective resources estimates based

upon project maturity which is appropriate where a potential accumulation

within a play is sufficiently well defined to present a viable drilling target.

“prospective resources” means quantities of petroleum estimated, as of a

given date, to be potentially recoverable from undiscovered accumulations by

application of future development projects. Prospective resources have both

an associated chance of discovery and a chance of development.

“proved reserves” are those reserves that can be estimated with a high

degree of certainty to be recoverable. It is likely that the actual remaining

quantities recovered will exceed the estimated proved reserves.

“reserves” are estimated remaining quantities of oil and natural gas and

related substances anticipated to be recoverable from known accumulations,

as of a given date, based on: (i) analysis of drilling, geological, geophysical

and engineering data; (ii) the use of established technology; and (iii) specified

economic conditions, which are generally accepted as being reasonable.

Reserves are classified according to the degree of certainty associated with

the estimates.

“risked” means adjusted for the probability of loss or failure in accordance

with the COGE Handbook.

35

Abbreviations

AB

AECO

bbl or bbls

bcf

boe

Btu

C*

°C

CAD or C$

CAGR

CGR

Chi CG

CROIC

C2

C3

C4

C5+

d

DCET

Deep SW

EBITDA

EUR

F&D

FD&A

ft

FX

FY

Gj

H1

H2

H2S

HH

IP 30

IP 90

IP 180

IP 270

IP 365

IPO

IRR

km

kpa

LGR

LNG

LPG

m

Mbbls

Mboe

Alberta

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

transmission system

barrels or barrels

billion cubic feet

barrels of oil equivalent

British thermal units

The drilling and completion cost allowance under the Alberta Modernized Royalty

Framework

Degrees celsius

Canadian dollars

compound annual growth rate

condensate/gas ratio

Chicago Citygate

cash return on invested capital

ethane

propane

butane

pentanes plus

day

drill complete and tie-in

The area that the company refers to as Deep Southwest that is shown in this

presentation

earnings before interest, taxes, depreciation and amortization

estimated ultimate recovery

finding and development cost

Finding, development and acquisition cost

feet

foreign exchange rate

full year

Gigajoule

first half of the year

second half of the year

hydrogen sulfide

Henry Hub

initial production for the first 30 days

initial production for the first 90 days

initial production for the first 180 days

initial production for the first 270 days

initial production for the first 365 days

initial public offering

internal rate of return

kilometres

Kilopascals

liquid/gas ratio

liquefied natural gas

liquefied petroleum gas

metres

thousand of barrels

thousands of barrels of oil equivalent

Mcf

MM

MMboe

Mmbtu

MMcf

MNTN. Hz

mo

Nest

Nest 1

Nest 2

NGL

NGPL

NGTL

NPV

NPV10

NPV20

NYMEX

OPEX

PDP

PP&E

PSI

prospectus

Prosp. Res.

Q1

Q2

Q3

Q4

Rich Gas

ROY

sh

Super Pad

TCPL

TSX

U.S.

USD or US$

Wapiti

WI

WTI

YE

YoY

YTD

1P

2C

2P

$MM or MM$

Δ

thousand cubic feet

million

million barrels of oil equivalent

million British thermal units

million cubic feet

Montney horizontal well

month

Both the Nest 1 and Nest 2 areas combined

The area that is contained within the primary development block of the Kakwa River Project that is shown

and described in this presentation

The higher return prospects that are contained within the primary development block of the Kakwa River

Project that is shown and described in this presentation

natural gas liquids

Natural Gas Pipeline Company of America pipeline system

NOVA Gas Transmission Ltd. Pipeline system

net present value

net present value discounted at an annual 10% discount rate

net present value discounted at an annual 20% discount rate

New York Mercantile Exchange

operating expense

gross proved developed producing reserves

Property, plant and equipment

pounds per square inch

supplemented PREP Prospectus filed by the Company on October 29, 2014

gross prospective resources (best estimate)

First quarter of the year

Second quarter of the year

Third quarter of the year

Fourth quarter of the year

the area that the company refers to as Rich Gas in this presentation

rest of year

share

decentralized processing plants that separate field condensate and natural gas

TransCanada Pipelines

Toronto Stock Exchange

United States of America

United Stated dollars

the area that the company refers to as Wapiti in this presentation

working interest

West Texas Intermediate

year-end

year-over-year

year to date

gross total proved reserves

gross best estimate contingent resources

gross total proved plus probable reserves

millions of dollars

change

36

TSX: VII.TO

4400, 525 – 8th Avenue SW

Calgary, AB T2P 1G1

T: (403) 718-0700

E: info@7genergy.com