Cequence Energy Ltd.Nov 15, 2019  · • Dunvegan oil –100% CQE inventory • Encouraging third party oil activity in other Montney benches Gas Large gas reserve with significant

TSX:CQE 1

Cequence Energy Ltd.November 15, 2019

2

FORWARD-LOOKING INFORMATION AND NON-IFRS MEASURES

Summary of Forward-Looking Statements or Information

Certain information included in this presentation constitutes forward-looking information under applicable securities legislation.This information relates to future events or future performance of the Company. Investors are cautioned that reliance on suchinformation may not be appropriate for making investment decisions. Many factors could cause the Company’s actual results,performance or achievements to vary from those described herein. The forward-looking information contained in this presentationis expressly qualified by this and other cautionary statements set forth in the continuous disclosure record of the Company.

The reporting and the measurement currency is the Canadian dollar. For the purpose of calculating unit costs, natural gas isconverted to a barrel of oil equivalent (“boe”) using 6,000 cubic feet of natural gas as equal to one barrel of oil unless otherwisestated. The term barrel of oil equivalent (boe) may be misleading, particularly if used in isolation. A boe conversion ratio for gas of 6Mcf:1 boe is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent avalue equivalency at the wellhead. This value ratio is significantly different from the energy equivalency ratio of 6:1 and using a 6:1ratio would be misleading as an indication of value.

See slide 20 for additional advisories.

Non-IFRS Measures

References in this presentation are made to terms commonly used in the oil and gas industry, including net debt and funds flowfrom (used in) operations which are not measures recognized by International Financial Reporting Standards (“IFRS”).

Net debt is a measure that provides Cequence’s total indebtedness. It is calculated as working capital deficiency (excludingcommodity contracts and lease liability) plus amounts outstanding in the Company’s Credit Facility plus the principal value of theTerm Loan. Cequence uses net debt as an estimate of the Company’s assets and obligations expected to be settled in cash.

Funds flow from operations is calculated as cash flow from operating activities before adjustments for decommissioning costsincurred and net change in non-cash working capital. The Company uses this measure to analyze operating performance andleverage and considers it a key measure as it demonstrates the Company’s ability to generate the cash flow necessary to fund futuregrowth through capital investment and to repay debt.

Reconciliations of net debt and funds flow from operations to the nearest IFRS measure, can be found in Cequence’s ManagementDiscussion & Analysis, which may be accessed through the SEDAR website (www.sedar.com). These measures may not be consistentwith the calculation of other companies.

Repaid$10.0 million pre-payment of the $60.0 million Term Loan

Improve

Amended the Term Loan• Extend maturity by 1 year to Oct 3, 2023• Fix interest rate at 5% eliminating escalation to

10% when funds flow from operations is equal to or greater than $40.0 million

• Cancel 1.8 million warrants

Invest

Issued 17.2 million common shares• $11.2 million private placement at $0.65/share

(Premium to June 27 closing price of $0.34/share)

• Canadian Development Expense on a “flow through basis” by December 2020

Benefit

• June 30, 2019 net debt to TTM funds flow from operations 4.1x compared to 4.8x before the transaction

• $0.5 million in annual interest savings or $2.1 million over the term of the Term Loan

3

RECAPITALIZE AND

IMPROVED BALANCE

SHEET

CORPORATE SUMMARY

2019GUIDANCE

WITHIN CASH FLOW

1. Net debt is calculated as working capital deficiency (excluding commodity contracts and lease liability) plus the aggregate principal amount of the Term Loan.

2. 2019 average production estimates on a per BOE basis are comprised of 75% natural gas and 25% oil and natural gas liquids. 2019 commodity prices included above average $56.75 WTI US/bbl and AECO price of $1.68 CAD/GJ.

3. Reserves evaluation by GLJ Petroleum Consultants Ltd. effective December 31, 2018. 4. Net asset value per share is the before tax discounted 10% reserve value using Jan 1, 2019 GLJ prices, net debt at

September 30, 2019, and common shares outstanding as at September 30, 2019.

(000’s, except per share, ratios, production and per unit references)

Common shares outstanding at September 30, 2019 41,784

Closing share price November 15, 2019 $0.18

52 week share price trading range - September 30, 2019 $0.17 to $1.00

September 30, 2019, net debt(1) $64,653

Funds flow from operations - 2019 Guidance $13,000

Net Debt(1)/Trailing twelve month funds flow from operations 5.8x

Forecast 2019 production(2) 5,800

Reserves P + P, December 31, 2018(3) 129 MMBoe

Net asset value per share(4) $9.10

Tax Pools at December 31, 2018 $616,400

Non-Capital Losses (included above) $289,200

4

WHY INVEST IN CEQUENCE

DUNVEGAN OIL GROWTH

PRESERVE MONTNEY UPSIDE

2019 SPEND WITHIN CASHFLOW

Oil

Investing in higher return commodities• Dunvegan oil – 100% CQE inventory• Encouraging third party oil activity in other

Montney benches

Gas

Large gas reserve with significant upside• 112 MMboe of proved plus probable Montney

reserves(1) with torque to improving gas price• Dawn contract for 40% of current production –

diversification from AECO

Facilities and

transport

Major facilities and firm egress in place• 120 MMcf/d processing built• 35,000 mcf/d – Simonette NGTL transport• 10,850 GJ/d Empress to Dawn transport• 600 bbl/d firm liquids transport

Financial

• Term Loan Oct 2023 maturity - 5% interest rate• Improving funds flow with lower interest,

improved realized gas price, higher oil weighting, and lower operating costs

5(1) Reserves evaluation by GLJ Petroleum Consultants Ltd. effective December 31, 2018.

1. Original oil in place (OOIP) is equivalent to DPIIP for purposes of this presentation. See page 16.2. Remaining locations are internal company estimates at YE 2018 based on current development plans and subject to change.

16 gross (14.5 net) sections identified with oil development

˃ 40o API oil

˃ Internal estimate of ~80 MMbbls OOIP (1) net to Cequence

˃ 26.0 gross, 24.5 net locations remaining (2)

˃ Solution gas gathered to Cequence/KANATA 13-11 gas plant

˃ Infrastructure synergy with Montney development

˃ Expect 8-10% recovery on primary and up to 20% recovery on waterflood

SIMONETTEDUNVEGANOIL PLAY

16-0810-09

06-06

All 3 Pools have similar OOIP/section ranges of 6-15 MMBOE

Simonette & Karr on primary solution gas drive

Kaybob South operator has initiated a pilot secondary recovery waterflood scheme• 1st Hz producer converted to injector late 2015• 2nd and 3rd converted late 2017• Positive early response on oil rates and GORs

6

(1) Reserves evaluation by GLJ Petroleum Consultants Ltd. effective December 31, 2018.(2) Proved undeveloped and probable locations are derived from the Company’s December 31, 2018 reserves evaluation as prepared by GLJ Petroleum

Consultants. Unbooked locations are internal estimates based on the Company’s prospective acreage. Unbooked locations do not have attributed reserves and there is no certainty that if drilled these locations would result in additional oil and gas reserves or production.

SIMONETTE DUNVEGANLIGHT OILINVENTORY

Progress to Date:Q4 2018 - 2.0 (2.0 net) wells: IP 90 flowing average rate per well: 406 boe/d, 60% oil˃ 15-04 (100% CQE): 164 mstb in first 12 monthsJanuary 1, 2019 Reserves:˃ TP: 2.9 MMboe 5.5 net locations $42 MM NPV10%˃ 2P: 5.3 MMboe 10.5 net locations $75 MM NPV10%˃ 14 Unbooked locations (2) - 100% Cequence working interest with anticipated lower gas oil ratios

5-7 facility2,000 bbls/d

740 HpCompressor

05-06 vertical delineation

9m gross interval

04-08 vertical100% WI landsIP30: 45 BOPD

15-04

Dunvegan 2018 YE Bookings (1) (2)

PUDProbableUnbooked Locations

Q4 2018 Rig ReleasesDrill Ready Locations

100% CQE

50% CQE

10-0416-02

7

SIMONETTE DUNVEGANLIGHT OILPERFORMANCE& METRICS

Strong Well Results˃ Actual well costs $4-4.5 MM/well: Target >2,000 m laterals, 40-50 frac stages (Tighter frac spacing)˃ 09-11, 15-04, 12-14 each paid out in under one year˃ Oil moving through 50% CQE owned 13-11 facility reducing 3rd party processing

$60 US WTI, $1.50/GJ CDN, $5USD diff flat 250 mbbl 160 mbbl

Costs (Drill, Complete, Equip) ($MM) $4.0 $4.0

Drilling Results

IP365 Production Rate (boe/d) 440 310

Reserves (MBBL) 250 160

Reserves (MBOE) 550 350

Economic Indicators

F&D ($/BOE) $7.27 $11.43

1st Yr Netback ($/boe) $26.37 $28.01

Recycle Ratio 3.6 2.5

ROR (%) 98% 40%

Payout (years) 1.1 1.8

NPV10% ($MM) $4.3 $1.6

Production Efficiency ($/boe-365) $9,100 $12,900

Dunvegan Oil Type Wells

8

DUNVEGAN OIL

SENSITIVITIES TO CAPITAL AND COMMODITY PRICE

Capital Sensitivity

˃ Internal CQE 2,000 m well model˃ $60 WTI US/bbl, ˃ $5 US/Edmonton differential,

$0.75 CAD/US exchange˃ $1.50 CAD/GJ AECO˃ MRF Alberta Crown Royalties

Price Sensitivity

˃ Internal CQE 2,000 m well model˃ $5 US/Edmonton differential,

$0.75 CAD/US exchange˃ $4 million well cost˃ MRF Alberta Crown Royalties

9

(1) See Forward-Looking Information and Definitions on page 16 for definition of DPIIP and total resource, Upper Montney only. DPIIP effective December 21, 2016, not re-evaluated in 2018

(2) Reserves evaluation by GLJ Petroleum Consultants Ltd. effective December 31, 2018.

(3) Internal estimate based on 300 m inter-well spacing

SIMONETTE MONTNEY

CQ

E M

on

tney

: 1

40

m –

17

5m

Th

ick

“Upper”Montney

“Lower”Montney

Nordegg

Paleozoic

100/11-16-061-27W5M

Historical CQE Hz

placement

Lower Montney

placement

LARGE “UPPER” MONTNEY RESOURCE & INVENTORY˃ Montney – 3.8 TCF gross “Upper” Montney resource-in-place (1) PDP: 6.7 MMboe (2)

˃ TP: 51 MMboe 51 gross (48.0 net) locations $123 MM NPV10%˃ 2P: 112 MMboe 86 gross (79.5 net) locations $339 MM NPV10%˃ Booked at 300 m inter-well spacing

WEST DEVELOPMENT AREA˃ Liquid yields of 45-100 bbl/MMcf˃ 21 sections of analogous western lands – 50 potential net “Upper” locations at 300 m

spacing (3) largely unbooked for reserves

OTHER MONTNEY ACTIVITY INCREASING˃ Recent third parties drilling “Lower & Middle” Montney benches nearby˃ 2 Lower Montney wells drilled in Simonette - both monobore (no intermediate casing)˃ 15-13 Lower Montney well: 2,260 m lateral RR November 2018

˃ February calendar day rate: 672 bbl/d oil & 1,038 mcf/d gas (845 boe/d)˃ March calendar day rate: 665 bbl/d oil, 1,145 mcf/d gas (855 boe/d)

10

07-15 Lwr Mont Producer

15-13 Lwr MontFeb ’19 cal day oil rate: 672 bbl/d

3rd Party Lwr Mont Test Spud Aug 16/19

MONTNEY OIL AND LIQUIDS DISTRIBUTION

˃ Most Industry activity is in the liquid rich gas phase

˃ Oil is expanding in multiple benches continuing up into B.C.

˃ Historic Simonette Upper Montney oil wells predominately under-stimulated.

˃ Recent industry oil successes moving toward CQE lands from Karr and Waskahigan

˃ Many wells need to be artificially lifted making well mechanics critical

11Map is internally generated based upon publicly available data in GeoScout.

“Upper”Montney

“Lower”Montney

Nordegg

Paleozoic

100/11-16-061-27W5M

12

LOWER MONTNEY OIL AND LIQUIDS DISTRIBUTION

˃ Lower Montney activity is typically less mature than other Montney benches

˃ Oil has been a significant production phase within the Lower Montney

˃ Recent encouraging results near Simonette include the Anegada well at 15-13-61-1W6

˃ IP 30: 672 bbls/d calendar day – 46 API

˃ Anegada spud a new Lower Montney oil well at 9-3-61-27W5 August 16, 2019

See Forward-Looking Information and Definitions on page 16. Map is internally generated based upon publicly available data in GeoScout.

“Upper”Montney

“Lower”Montney

Nordegg

Paleozoic

100/11-16-061-27W5M

SIMONETTE EGRESS

MAJOR INFRASTRUCTURE BUILT

13-11 Facility – Curr. capacity-Compression 100 MMcf/d-Refrigeration 120 MMcf/d-Cond stabilization 4,500 bpd

Cequence AllianceMeter StationCapacity 120 MMcf/d

NGTL meter station- March 2016 - 200 MMcf/d

CQE 9-10Field Compressor

Alliance/Aux SableDeep Cut PlantChicago, Illinois

Pembina LatorTruck Terminal

Proposed Pembina Simonette Terminal

Company Infrastructure

˃ 120 MMcfd refrigeration plant (50% WI)

˃ 75% available capacity

˃ Sales gas heat content 41.7 GJ/e3m3 (1,120 Btu/scf)

˃ All major gathering system built

˃ Multi-well pad sites built or acquired for entire drilling inventory

˃ 10,000 to 12,000 bbls/d of water disposal capability

Production Egress

˃ Dual connection to NGTL and Alliance pipeline systems

˃ 35,000 mcf/d firm capacity on NGTL

˃ 10,850 GJ/d firm capacity to Dawn to 2026

˃ 320 MMcfd metering capacity

˃ Pembina liquid terminals in close proximity to 13-11-62-27W5 Facility

13

LARGE RECOGNIZED UPPERMONTNEYINVENTORY WITH TORQUE TO INCREASING GAS PRICES

(1) Assumes 30 Bbls/MMcf of NGL’s and condensate▪ Includes 5% GORR, Opex $2.50 per Boe incremental. $0.27/mcf midstream capital fee excluded▪ Underutilized NGTL firm transport of $0.18/GJ excluded, ▪ 5% GORR illustrative. Actual GORR range from 0% to 12.5%

(2) Internal estimate based on 300m interwell spacing

˃ Mean booked well length 2,500 m (79.5 net wells)

˃ Western wells provide commercial inventory of 50 potential net locations (2)

˃ Western lands have strong value with torque to liquid prices

˃ Eastern lands have strong torque to increasing gas prices

˃ Successful 3rd Party monobore wells expect $1 million less per well with steady program (no intermediate casing and shorter drilling times)

East

Montney (1)

West

Montney

$8.0 $8.0

IP30 Production Rate (MMcf/d) 8.5 4.0

Reserves (MBOE) 1,650 1,050

ORGIP (Bcf) 8.5 4.3

F&D ($/BOE) $4.80 $7.60

1st Yr Netback ($/boe) $15.42 $26.05

Recycle Ratio 3.2 3.4

ROR (%) 38% 44%

Payout (Years) 2.1 1.9

NPV10% ($M) $5.0 $6.0

Production Efficiency ($/boed-365) $8,100 $13,200

$60 WTI, $1.50/GJ CDN, $5/bbl diffCosts (Drill, Complete, Equip) ($MM)

Drilling Results

Economic Indicators

14

UPPER MONTNEY ECONOMIC SENSITIVITIES

TORQUE TO GAS PRICES ABOVE $2.00 CAD/GJ

Capital Sensitivity

˃ Internal CQE East & West models˃ $60 WTI US/bbl, ˃ $5 US/Edmonton differential, $0.75

CAD/US exchange˃ $1.50 CAD/GJ AECO

Price Sensitivity

˃ Internal CQE East & West models˃ $5 US/Edmonton differential, $0.75

CAD/US exchange˃ $8 million well cost

Assumes 30 Bbls/MMcf of NGL’s and condensate▪ Includes 5% GORR, Opex $2.50 per Boe incremental,

$0.27/mcf midstream capital fee excluded▪ Underutilized NGTL firm transport of $0.20/GJ excluded,

AECO gas price▪ 5% GORR illustrative. Actual GORR range from 0% to 12.5%

15

HEDGING&

MARKETING

Contract Type Volume Price (Cdn$)

GAS GJ/d

2019 October 1, 2019 – October 31, 2019 Swap 5,000 $1.37/GJ AECO

2019/20 Nov 1, 2019 – March 31, 2020 Swap 5,000 $2.11/GJ AECO

OIL bbl/d

2019 October 1, 2019 – December 31, 2019 Swap 400 $85.29/bbl

2019 October 1, 2019 – December 31, 2019 Swap 100 $86.53/bbl

2020 January 1, 2020 – June 30, 2020 Swap 100 $83.12/bbl

˃ 10,850 GJ/d contract to Dawn, Ontario to March 31, 2028, 40% of Corporate gas

˃ 35 MMcfd of NGTL firm service to March 31, 2026

˃ 600 bbl/d oil firm service on Pembina system to December 31, 2021

16

WHY INVEST IN CEQUENCE?

• Developing highly commercial Dunvegan oil - 100% CQE lands

• 112 MMboe recognized proved and probable Montney reserves(1) with torque to improving gas prices

• Emerging upside oil opportunities in other Montney benches

• Market diversification (Dawn), major facilities and firm egress in place with excess capacity

• Netback improvement through price management, production optimization, and cost control

• Term Loan maturity October 2023 with 5% interest rate

17

(1) Reserves evaluation by GLJ Petroleum Consultants Ltd. effective December 31, 2018.

APPENDIX

18

• Todd Brown CEO

• Allan Mowbray VP Finance and CFO

• Dave Robinson VP Ex and Chief Geologist

• Chris Soby VP Land and Corporate Development

• Erin Thorson Controller

Management Team

• Don Archibald – Chairman

• Peter Bannister

• Todd Brown

• Howard Crone

• Brian Felesky

• Dan O’Neil

Board of Directors

MANAGEMENT AND BOARD

19

20

FORWARD-LOOKING STATEMENTS OR INFORMATION AND DEFINITIONS

Forward Looking Information: Certain statements included in this presentation constitute forward-looking statements or forward-looking information (collectively,“forward-looking information”) under applicable securities legislation. Certain information included in this presentation also constitutes future-oriented financialinformation (“FOFI”) under applicable securities legislation. Such forward-looking information and FOFI is provided for the purpose of providing information aboutmanagement’s current expectations and plans relating to the future. Readers are cautioned that reliance on such information may not be appropriate for other purposes,such as making investment decisions. Forward-looking information typically contains statements with words such as “anticipate”, “believe”, “expect”, “plan”, “intend”,“estimate”, “propose”, “project” or similar words suggesting future outcomes or statements regarding an outlook. Forward-looking information and FOFI concerningCequence in this presentation may include, but is not limited to, statements or information with respect to: guidance, forecasts and related assumptions; expectedproduction growth and cash flow growth and the respective timing thereof; capital spending; expected resource potential and future reserves; hedging objectives; businessstrategy and objectives; type curves; drilling, development and exploration plans and the timing, associated costs and results thereof; future net debt and funds flow;commodity pricing and expected royalties; costs associated with operating in the oil and natural gas business; and future production levels, including the compositionthereof. Forward-looking statements or information are based on a number of factors and assumptions which have been used to develop such statements and informationbut which may prove to be incorrect. The Company believes that the expectations reflected in such forward-looking information and FOFI are reasonable; however, unduereliance should not be placed on forward-looking information or FOFI because the Company can give no assurance that such expectations will prove to be correct. Inaddition to other factors and assumptions which may be identified in this presentation, assumptions have been made regarding, among other things: the impact ofincreasing competition; the timely receipt of any required regulatory approvals; the ability of the Company to obtain qualified staff, equipment and services in a timely andcost efficient manner; the ability of the operator of the projects which the Company has an interest in to operate the field in a safe, efficient and effective manner; theability of the Company to obtain financing on acceptable terms; field production rates and decline rates; the ability to replace and expand oil and natural gas reservesthrough acquisition, development or exploration; the timing and costs of operating the Company’s business; the ability of the Company to secure adequate producttransportation; future oil and natural gas prices; currency, exchange and interest rates; the regulatory framework regarding royalties, taxes and environmental matters; andthe ability of the Company to successfully market its oil and natural gas products. Readers are cautioned that the foregoing list is not exhaustive of all factors andassumptions which have been used.

Forward-looking information and FOFI is based on current expectations, estimates and projections that involve a number of risks and uncertainties which could cause actualresults to differ materially from those anticipated by the Company and described in the forward-looking information and FOFI. These risks and uncertainties may causeactual results to differ materially from the forward-looking information and FOFI. The material risk factors affecting the Company and its business are described in theCompany’s Annual Information Form which is available at SEDAR at www.sedar.com.

The forward-looking information and FOFI contained in this presentation is made as of the date hereof and the Company undertakes no obligation to update publicly orrevise any forward-looking statements or information, whether as a result of new information, future events or otherwise unless required by applicable securities laws. Theforward-looking statements or information contained in this presentation are expressly qualified by this cautionary statement.

Discovered Petroleum Initially in Place (“DPIIP”) Resources in Place and Contingent Resources: DPIIP is equivalent to discovered resources and is defined in the CanadianOil and Gas Evaluation Handbook (“COGEH”) as that quantity of petroleum that is estimated, as of a given date, to be contained in known accumulations prior to production.The recoverable portion of discovered petroleum initially in place includes production, reserves and contingent resources; the remainder is unrecoverable. ContingentResources are defined in COGEH as those quantities of petroleum estimated to be potentially recoverable from known accumulations using established technology ortechnology under development, but which are not currently considered to be economically recoverable due to one or more contingencies. Contingencies may includefactors such as economic, legal, environmental, political, and regulatory matters, or a lack of markets. It is also appropriate to classify as contingent resources the estimateddiscovered recoverable quantities associated with a project in the early evaluation stage. The Contingent Resources estimates and the DPIIP estimates are estimates onlyand the actual results may be greater or less than the estimates provided herein. There is no certainty that it will be commercially viable to produce any portion of theresources except to the extent identified as proved or probable reserves.

Cequence has presented certain type curves and well economics which are based on the Company’s historical production in the Simonette development area, in addition toproduction history from analogous Montney and Dunvegan developments located in close proximity. Such type curves and well economics are useful in understandingmanagement's assumptions of well performance in making investment decisions in relation to development drilling and for determining the success of the performance ofdevelopment wells; however, such type curves and well economics are not necessarily determinative of the production rates and performance of existing and future wells.In this presentation, estimated ultimate recovery represents the estimated ultimate recovery associated with the type curves presented; however, there is no certainty thatCequence will ultimately recover such volumes from the wells it drills.

20

TSX:CQE 21

www.cequence-energy.com1400, 215 9th Ave S.W. Calgary AB T2P 1K3

Phone: 403-229-3050 Fax: 403-229-0603

Contacts:Todd BrownCEO [email protected]

Allan MowbrayVP Finance and [email protected]

TSX:CQE