1

POSITIONED FOR LIQUIDS‐RICH GAS GROWTHSeptember 2017 

TSX:CQE 2

FORWARD‐LOOKING INFORMATION AND DEFINITIONS

Summary of Forward‐Looking Statements or Information

Certain information included in this presentation constitutes forward‐looking information under applicable securities legislation. Thisinformation 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 presentation isexpressly 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 is convertedto a barrel of oil equivalent (“boe”) using 6,000 cubic feet of natural gas as equal to one barrel of oil unless otherwise stated. The termbarrel of oil equivalent (boe) may be misleading, particularly if used in isolation. A boe conversion ratio for gas of 6 Mcf:1 boe is basedon an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at thewellhead. This value ratio is significantly different from the energy equivalency ratio of 6:1 and using a 6:1 ratio would be misleadingas an indication of value.

See slide 21 for additional advisories.

NON‐GAAPMEASUREMENTS

References are made to terms commonly used in the oil and gas industry, including operating netback, net debt, and funds flow from(used in) operations. Operating netback is not defined by IFRS in Canada and is referred to as a non‐GAAP measure. Operatingnetback equals per boe revenue less royalties, operating costs and transportation costs. Management utilizes this measure to analyzethe operating performance of its assets and operating areas, to compare results to peers and to evaluate drilling prospects.

Net debt is a non‐GAAP measure that is calculated as working capital (deficiency) less the principal value of senior notes.  For this calculation, Cequence uses the principal value of the senior notes rather than the carrying value on the statement of financial position as it reflects the amount that will be repaid upon maturity. Cequence uses net debt as it provides an estimate of the Company’s assets and obligations expected to be settled in cash.

Funds flow from (used in) operations is a non‐GAAP term that represents cash flow from operating activities before adjustments fordecommissioning liabilities expenditures and net changes in non‐cash working capital. The Company evaluates its performance basedon earnings and funds flow from (used in) operations. The Company considers funds flow from (used in) operations a key measure asit demonstrates the Company’s ability to generate the cash flow necessary to fund future growth through capital investment and torepay debt. The Company’s calculation of funds flow from (used in) operations may not be comparable to that reported by othercompanies.

Operating netback is not defined by IFRS in Canada and is referred to as a non‐GAAP measure. Operating netback equals per boerevenue less royalties, operating costs and transportation costs. Management utilizes this measure to analyze operating performanceof its assets and operating areas, compare results to peers and to evaluate drilling prospects.

TSX:CQE 3

ESTABLISHED MONTNEY/DEEP BASIN PRODUCER

Contiguous, high‐WI land position

Multi‐year inventory

Facilities and take‐away capacity

Improved drilling / completion designs

Better per‐well production results

Improved operating cost structure

Trading Symbol TSX: CQE

Q2 2017 average production 8,502 boe/d

52‐week trading range $0.13 ‐$0.37

Shares outstanding 246 MM

Insider ownership (1) 10.5%

Market capitalization (2) $34 MM

Net debt ‐ June 30, 2017(3)   $68 MM

Net debt/Funds Flow– H1, 2017(4) 2.4X

2017 natural gas hedges (approximately 60% of total volume) $2.78/GJ

Reserves P + P, December 31, 2016 136 MMBoe

TSX:CQE 4

OVERVIEW

(1) Insider ownership is 24% including private equity shareholder represented on the Board of Directors.(2) Based on Cequence stock price of $0.14 per share.(3) Net debt is calculated as working capital deficiency and the principal value of the senior notes.(4) Calculated as net debt divided by annualized H1 2017 funds flow from operations of $14.1 MM. 

TSX:CQE

STRATEGY˃Q2 G&A expenditures:down by 39% year‐over‐year

˃Q2 operating costs: 7% reduction to $7.53/boe

Lower Cost Structure

˃Montney design changes and netback initiatives have improved economics

˃Dunvegan oil results above analog average

Improved Well Performance

˃$60 MM subordinated term debt (Oct. 2018)

˃$20 MM undrawn senior credit facility

˃$10 MM raised in Oct. 2016 private placement 

Stable Balance Sheet

˃87.5 net booked Montneylocations

˃ Expanding Dunveganinventory

˃ Infrastructure in place. No material plant or pipe costs required

Large Recognized Inventory 

(1) Average production estimates on a per BOE basis are comprised of 85% natural gas and 15% oil and natural gas liquids.(2) Funds flow from operations is calculated as cash flow from operating activities before adjustments for decommissioning liabilities expenditures and net 

changes in non‐cash working capital.  (3) Net debt is calculated as working capital (deficiency) less the aggregate principal amount of the senior notes.

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

Revised YearEnded

December 31, 2017

Average production, boe/d (1)  8,500‐8,700

Funds flow from operations ($)(2)   23,000

Funds flow from operations per share(2)  0.10

Capital expenditures, ($)  24,000

Operating and transportation costs ($/boe)  10.25

G&A costs ($/boe)   1.60

Royalties (% revenue)  8

Crude – WTI (US$/bbl)   49.25

Natural gas – AECO (Cdn$/GJ)   2.50

Period end, net debt ($) (3)  65,000

Weighted average basic shares outstanding  245,500 

TSX:CQE 6

2017GUIDANCE

CQE 16‐33

2017 drills

Western areaHigher liquids (35+ bbls/MMcf)2.7% average GORR

TSX:CQE 7

MULTIPLE ZONES     Stacked horizons: Dunvegan, Gething, Falher, Wilrich, Montney

BIG RESOURCESAll zones – 132 MMboe proved plus probable booked reserves (1) Montney – 3.8 TCF gross Montney resource‐in‐place  (2)

˃ PDP: 10.6 MMboe

LARGE INVENTORY˃ TP: 56.7 MMboe (+19% from 2015) 60 gross (56.5 net) wells˃ 2P: 112.4 Mmboe (+15% from 2015)  93 gross (87.5 net) wells˃ 2P + Best Estimate contingent 121 (114) wells˃ Booked at 300 m inter‐well spacing

WEST DEVELOPMENT AREA˃ Liquid yields of 45‐100 bbl/MMcf

˃ 16‐33 Montney: IP 365 897 boe/d (22% liquids)˃ 2017 Montney: IP30 840 boe/d (36% liquids)

˃ 21 sections of analogous western lands – 50 potential net wells at 300 m spacing, (3)largely unbooked for reserves

(1) Reserves evaluation by GLJ Petroleum Consultants Ltd. effective December 31, 2016.

(2) See Forward‐Looking Information and Definitions for definition of DPIIP and total resource, Upper Montney only.

(3) Internal estimate based on 300 m inter‐well spacing; 26 locations are included in the reserves evaluation by GLJ at December 31, 2016.

SIMONETTE MONTNEY

TSX:CQE 8

1.Type curves are internally generated, see definitions on page 21.2.Price assumptions: Cal 17 AECO $2.83/Mcf and WTI US$56/bbl.

WEST AREA CHARACTERIZATIONDouble the condensate rate vs the historical type curves˃ Condensate rate 2X historical˃ Higher netback production

LIQUIDS‐RICHLiquids sales 98% high‐value pentanes plus

COST‐EFFICIENTLess than 15 ppm H2S: $0.30/mcf lower treating cost than 2014/2015 program

EXPANDED INVENTORYWest area inventory unbooked

CEQUENCE SIMONETTE

TSX:CQE 9

˃ Montney drilling design changes delivered 30+% lower cost per meter˃ Simplified drilling path saves time

˃ Cemented production casing (less hole conditioning)

˃ Increased completion effectiveness˃ Longer laterals with 2 x tighter frac spacing

˃ Significant completion & production flexibility 

˃ Better hydraulic isolation with cement = frac placement where you want 

˃ Drill, Complete, Equip Costs ranges:˃ $8.0 to $8.6 MM per 3,000 m well + $0.3 MM on lease tie‐in

˃ 15+% savings with steady drilling program

15‐28 stages15‐28 stages 26 stages26 stages

1.0 t/m 1.2 t/m1.0 t/m

0.5 t/m

0.5 t/m

15‐28 stages 26 stages

1.0 t/m 1.2 t/m1.0 t/m

0.5 t/m

0.5 t/m

DRIVING IMPROVED PERFORMANCE

TSX:CQE10

COMMERCIAL INVENTORY

(1)  Assumes 30 Bbls/MMcf of NGL’s and condensate Includes 5% GORR, Opex $2.50 per Boe incremental, $0.27/mcf midstream capital Assumes NGTL transport 2017 onward of $0.20/GJ GORR range from 0% to 12.5%

(2) Internal estimate based on 300m interwell spacing, 26 locations are included in the reserves evaluation by GLJ at December 31, 2016.

˃ Mean booked well length increased 25% to 2,500 m (87.5 net wells)

˃ Operating cost initiatives captured in economics

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

˃ Western lands have strong value with torque to liquid prices 

˃ 15+% capital improvements can be realized with steady program

2,500 m Mean Well (1)

2017 West Montney

16‐33 ‐ 3% GORR (50 

bbl/MMcfd C5)

Length (m) 2,500 2,850 3,050

Total ($MM) $7.7 $8.0 $8.6

IP30 Production Rate (MMcf/d) 6.0 3.2 6.8Reserves (MBOE) 1,120 845 1,500

F&D ($/BOE) $6.88 $9.47 $5.731st Yr Netback ($/boe) $17.70 $28.30 $22.30Recycle Ratio  2.6 3.0 3.9ROR (%) 35% 30% 70%Payout (Years) 2.5 2.6 1.3NPV10% ($M) $4.5 $3.8 $10.0Breakeven Gas Price ($C/GJ)               (at $50.00 WTI/Bbl)

$1.90 $1.25 $1.01

Production Efficiency ($/boed‐365) $11,600 $16,360 $9,600

$50 WTI, $3.00/GJ CDN Parameters

Costs (Drill, Complete, Equip)

Drilling Results

Economic Indicators

11

KARR ANALOG

SIMONETTE

Net Pay 9m

Karr Type Log 6‐6

Dunvegan Oil Pool

DunveganGas Pool

15% Ø

Net Pay 10m

Simonette Type Log CQE 10‐9

15% Ø

DunveganGas Pool

1. Original oil in place (OOIP) is equivalent to DPIIP for purposes of this presentation.  See page 21.

9 gross (7.5 net) sections identified with oil development ˃ 40o API oil˃ 24 net locations with average 1,900 meter lateral length˃ 60 MMbbls OOIP (1) net to Cequence

˃ 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

TSX:CQE

SIMONETTEDUNVEGANOIL PLAY

12

(1) Reserves evaluation by GLJ Petroleum Consultants Ltd. effective December 31, 2016.

(2) Proved undeveloped and probable locations are derived from the Company’s December 31, 2016 reserves evaluation as prepared by GLJ Petroleum Consultants.  Unbooked locations are internal estimates based on the Company’s prospective acreage.  Unbookedlocations 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.TSX:CQE

SIMONETTEDUNVEGANLIGHT OIL

5‐7 Battery2,000 bbls/d

1,150 HpCompressor

Existing Gas LineFuture Oil/Water 

Line

Gas to 13‐11

July 15 – treater & Pembina connection

Progress to Date and 2017 Development Plan˃ Winter 2016/17 cost:

˃ Drill, complete, equip & tie‐in: $4 MM/well˃ 11% below budget

˃ 9‐11 produced 76 Mbbl in 160 operating days

˃ 2,000 bbl/d facility built with solution gas gathering to CQE/KANATA Simonette plant

˃ 2‐3 Net locations planned Q4 2017/Q1 2018

˃ July 2017: Connection to Y battery & Pembina

$4.5 $4.0IP365 Production Rate (bbl/d) 220 220Reserves (MBOE) 540 540

F&D ($/BOE) $8.30 $7.401st Yr Netback ($/boe) $27.74 $27.74Recycle Ratio 3.3 3.7ROR (%) 80% 100%+Payout (Years) 1.2 1.0NPV10% ($M) $4.3 $4.8Breakeven Oil Price ($US/bbl)(at $3.00/GJ Gas) $23.40 $21.35Production Efficiency ($/boed‐365) 10,150 9,000

Economic Indicators

$50 US WTI, $3.00/GJ CDN 2,000 m well 2,000 m wellCosts (Drill, Complete, Equip)($MM)

(1)

(2)

TSX:CQE 13

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) on‐stream Jan. 2016

˃ 60% 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

˃ ½‐cycle economics applicable

Production Egress

˃ Dual connection to NGTL and Alliance pipeline systems

˃ Firm capacity on NGTL, growing to 35,000 GJ/d effective April 1, 2018

˃ NGTL transport $0.20/GJ to AECO

˃ 200 MMcfd metering capacity

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

Contract Type Volume GJ/d

Price Cdn$

GAS

2017 July 1, 2017 – September 30, 2017 Average Gas Swap 27,500 $2.80/GJ AECO

2017 October 1, 2017 – December 31, 2017 Average Gas Swap 20,027 $2.76/GJ AECO

2018 January 1, 2018 – March 31, 2018 Average Gas Swap 12,500 $3.01/GJ AECO

OIL Volumebbl/d

Price Cdn$

2017 April 1, 2017 – December 31, 2017 Swap 400 $69.58/bbl

2018 January 1, 2018 – March 31, 2018 Swap 300 $70.00/bbl

2018 April 1, 2018 – June 30, 2018 Swap 300 $61.22/bbl

TSX:CQE 14

HEDGING

TSX:CQE 15

WHY OWN CQE?

(1) Recurring G&A expenses and excluded restructuring charges of $1.9 million incurred in 2016.(2) Reserves evaluation by GLJ Petroleum Consultants Ltd. effective December 31, 2016. 

• Improved operating cost structure with leverage to development economics

• YTD 34% lower G&A costs (1)Improved Costs

•136 MMboe proved + probable reserves (86% gas)Large Recognized Reserves(2)

•Encouraging high liquid West Montney Lands•Excellent Dunvegan oil results with large inventory 

Results

•Major facilities in place with connection to NGTL and Alliance pipelinesInfrastructure

•Low break even gas price•Higher liquids productionTorque

•Lean operations focused team Restructured

TSX:CQE 16

APPENDIX

• Todd BrownCEO

• Dave GillisEVP and CFO

• Dave RobinsonVP Ex and Chief Geologist

• Chris SobyVP Land and Corporate Development

• Erin ThorsonController

• Todd BrownCEO

• Dave GillisEVP and CFO

• Dave RobinsonVP Ex and Chief Geologist

• Chris SobyVP Land and Corporate Development

• Erin ThorsonController

Management Team

• Don Archibald ‐ Chairman• Peter Bannister• Todd Brown• Howard Crone• Brian Felesky• Daryl Gilbert• Frank Mele

• Don Archibald ‐ Chairman• Peter Bannister• Todd Brown• Howard Crone• Brian Felesky• Daryl Gilbert• Frank Mele

Board of Directors

TSX:CQE 17

MANAGEMENT AND BOARD

TSX:CQE 18

SIMONETTE DEEP BASIN STACK

Dunvegan 

Falher Bluesky / Gething

MontneyWilrich  

Simonette Upper

CURRENT HORIZONTAL TARGET ZONE

POTENTIAL HORIZONTAL TARGET ZONE

TSX:CQE

MULTIPLE ZONES WITH SIGNIFICANT RESOURCE POTENTIAL AT SIMONETTE

5‐25 Bcf5‐10 MMbbl

5‐24 Bcf5‐24 Bcf

5‐25 Bcf

30‐60 Bcf

Dunvegan Gas

Dunvegan OilFalherWilrich

Gething

Upper Montney

Zone Total ResourcePotential/Sec (1)

2,400m

2,950m

3,100m

2,700m

2,500m

2,800m

(1)  See Forward‐Looking Information and Definitions for definition of total resource

‐$4.00

‐$2.00

$0.00

$2.00

$4.00

$6.00

$8.00

$10.00

$12.00

$14.00

$16.00

2010 2011 2012 2013 2014 2015

FD&A ($/Boe)

Proved + Probable (Incl FDC)

TSX:CQE 20

RESERVES AND FINDING COSTS –SOLID GROWTH PER SHARE IN RESERVES

0

1

2

3

4

5

6

0

200

400

600

800

1000

1200

2010 2011 2012 2013 2014 2015

2P Reserve Value ($MM)

Reserve Value2P per share

GLJ Proved + Probable  NPV 10%

$1,004

$854

$482$525

$715

$797

0.0

0.1

0.2

0.3

0.4

0.5

0.6

0.7

0

20

40

60

80

100

120

140

2010 2011 2012 2013 2014 2015

Proved + Probable (2)Total Proved2P per share

113

49

67

91

118126

Reserves (MMboe)

Certain statements included in this presentation constitute forward‐looking statements or forward‐looking information under applicable securities legislation.Such forward‐looking statements or information are provided for the purpose of providing information about management’s current expectations and plansrelating to the future. Readers are cautioned that reliance on such information may not be appropriate for other purposes, such as making investmentdecisions. Forward‐looking statements or information typically contain 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 statements or informationconcerning Cequence in this presentation may include, but are not limited to, statements or information with respect to: guidance, forecasts and relatedassumptions; expected production growth and cash flow growth and the respective timing thereof; capital spending; expected resource potential and futurereserves; hedging objectives; business strategy and objectives; type curves; drilling, development and exploration plans and the timing, associated costs andresults 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 composition thereof. Forward‐looking statements or information are based on a number of factors andassumptions which have been used to develop such statements and information but which may prove to be incorrect. The Company believes that theexpectations reflected in such forward‐looking statements or information are reasonable; however, undue reliance should not be placed on forward‐lookingstatements because the Company can give no assurance that such expectations will prove to be correct. In addition to other factors and assumptions whichmay be identified in this presentation, assumptions have been made regarding, among other things: the impact of increasing competition; the timely receiptof any required regulatory approvals; the ability of the Company to obtain qualified staff, equipment and services in a timely and cost efficient manner; theability of the operator of the projects which the Company has an interest in to operate the field in a safe, efficient and effective manner; the ability of theCompany 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 adequateproduct transportation; future oil and natural gas prices; currency, exchange and interest rates; the regulatory framework regarding royalties, taxes andenvironmental matters; and the ability of the Company to successfully market its oil and natural gas products. Readers are cautioned that the foregoing list isnot exhaustive of all factors and assumptions which have been used.

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

The forward‐looking statements or information contained in this presentation are made as of the date hereof and the Company undertakes no obligation toupdate publicly or revise any forward‐looking statements or information, whether as a result of new information, future events or otherwise unless requiredby applicable securities laws. The forward‐looking statements or information contained in this presentation are expressly qualified by this cautionarystatement.

Discovered Petroleum Initially in Place (“DPIIP”) Resources in Place and Contingent Resources: DPIIP is equivalent to discovered resources and is defined in theCanadian Oil and Gas Evaluation Handbook (“COGEH”) as that quantity of petroleum that is estimated, as of a given date, to be contained in knownaccumulations prior to production. The recoverable portion of discovered petroleum initially in place includes production, reserves and contingent resources;the remainder is unrecoverable. Contingent Resources are defined in COGEH as those quantities of petroleum estimated to be potentially recoverable fromknown accumulations using established technology or technology under development, but which are not currently considered to be economically recoverabledue to one or more contingencies. Contingencies may include factors such as economic, legal, environmental, political, and regulatory matters, or a lack ofmarkets. It is also appropriate to classify as contingent resources the estimated discovered recoverable quantities associated with a project in the earlyevaluation stage. The Contingent Resources estimates and the DPIIP estimates are estimates only and the actual results may be greater or less than theestimates provided herein. There is no certainty that it will be commercially viable to produce any portion of the resources except to the extent identified asproved 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 to production history from analogous Montney developments located in close proximity. Such type curves and well economics are useful inunderstanding management's assumptions of well performance in making investment decisions in relation to development drilling and for determining thesuccess of the performance of development wells; however, such type curves and well economics are not necessarily determinative of the production ratesand performance of existing and future wells. In this presentation, estimated ultimate recovery represents the estimated ultimate recovery associated withthe type curves presented; however, there is no certainty that Cequence will ultimately recover such volumes from the wells it drills.

Certain statements included in this presentation constitute forward‐looking statements or forward‐looking information under applicable securities legislation.Such forward‐looking statements or information are provided for the purpose of providing information about management’s current expectations and plansrelating to the future. Readers are cautioned that reliance on such information may not be appropriate for other purposes, such as making investmentdecisions. Forward‐looking statements or information typically contain 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 statements or informationconcerning Cequence in this presentation may include, but are not limited to, statements or information with respect to: guidance, forecasts and relatedassumptions; expected production growth and cash flow growth and the respective timing thereof; capital spending; expected resource potential and futurereserves; hedging objectives; business strategy and objectives; type curves; drilling, development and exploration plans and the timing, associated costs andresults 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 composition thereof. Forward‐looking statements or information are based on a number of factors andassumptions which have been used to develop such statements and information but which may prove to be incorrect. The Company believes that theexpectations reflected in such forward‐looking statements or information are reasonable; however, undue reliance should not be placed on forward‐lookingstatements because the Company can give no assurance that such expectations will prove to be correct. In addition to other factors and assumptions whichmay be identified in this presentation, assumptions have been made regarding, among other things: the impact of increasing competition; the timely receiptof any required regulatory approvals; the ability of the Company to obtain qualified staff, equipment and services in a timely and cost efficient manner; theability of the operator of the projects which the Company has an interest in to operate the field in a safe, efficient and effective manner; the ability of theCompany 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 adequateproduct transportation; future oil and natural gas prices; currency, exchange and interest rates; the regulatory framework regarding royalties, taxes andenvironmental matters; and the ability of the Company to successfully market its oil and natural gas products. Readers are cautioned that the foregoing list isnot exhaustive of all factors and assumptions which have been used.

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

The forward‐looking statements or information contained in this presentation are made as of the date hereof and the Company undertakes no obligation toupdate publicly or revise any forward‐looking statements or information, whether as a result of new information, future events or otherwise unless requiredby applicable securities laws. The forward‐looking statements or information contained in this presentation are expressly qualified by this cautionarystatement.

Discovered Petroleum Initially in Place (“DPIIP”) Resources in Place and Contingent Resources: DPIIP is equivalent to discovered resources and is defined in theCanadian Oil and Gas Evaluation Handbook (“COGEH”) as that quantity of petroleum that is estimated, as of a given date, to be contained in knownaccumulations prior to production. The recoverable portion of discovered petroleum initially in place includes production, reserves and contingent resources;the remainder is unrecoverable. Contingent Resources are defined in COGEH as those quantities of petroleum estimated to be potentially recoverable fromknown accumulations using established technology or technology under development, but which are not currently considered to be economically recoverabledue to one or more contingencies. Contingencies may include factors such as economic, legal, environmental, political, and regulatory matters, or a lack ofmarkets. It is also appropriate to classify as contingent resources the estimated discovered recoverable quantities associated with a project in the earlyevaluation stage. The Contingent Resources estimates and the DPIIP estimates are estimates only and the actual results may be greater or less than theestimates provided herein. There is no certainty that it will be commercially viable to produce any portion of the resources except to the extent identified asproved 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 to production history from analogous Montney developments located in close proximity. Such type curves and well economics are useful inunderstanding management's assumptions of well performance in making investment decisions in relation to development drilling and for determining thesuccess of the performance of development wells; however, such type curves and well economics are not necessarily determinative of the production ratesand performance of existing and future wells. In this presentation, estimated ultimate recovery represents the estimated ultimate recovery associated withthe type curves presented; however, there is no certainty that Cequence will ultimately recover such volumes from the wells it drills.

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FORWARD‐LOOKING STATEMENTS OR INFORMATION AND DEFINITIONS

SUSTAINABLE COST IMPROVEMENTS

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13% Decrease in YTD Operating Expenses

˃ Performance tested alternative chemical suppliers  

˃ Industry coordinated services

˃ Streamlined field operations

˃ Initiated water disposal solution

36% Decrease in YTD Administrative Expenses

˃ Rationalized staff to activity levels

˃ Relocated office and reduced discretionary costs

$/boe

Six months ended June 30,2017

Six months ended June 30,2016 Change

Operating expenses $6.89 $7.93 ($1.04)

Capital midstream fees(1) $1.03 $1.20 ($0.17)

Total operating expenses $7.92 $9.13 ($1.21)

G&A Expenses (2) $2,232 $3,614 ($1,382)

G&A Expense/boe $1.40 $2.20 ($0.80)

(1) Includes capital midstream fees only.(2) 2016 G&A Expenses exclude severances of $1,931. 

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(1) Yield represents field condensate only. (2) Illustrated transportation cost is $0.20/GJ gas on NGTL and $6/bbl for 

liquids trucking and pipeline tariff at Lator terminal.

Recent Results

˃ Increased netbacks˃ C5 rate double historical average well(1)

˃ GORR 1‐3% vs. 8‐12%˃ Op Costs $2.00/boe lower (improved cost structure, lower H2S content)

˃ Midstream inlet raw gas charge˃ Transport higher for C5 production(2)

2017 Montney 16‐33C5 Yield (bbl/mmcf) 27 95 50

Gas Rate (MMcf/d) 6,000 3,200 6,800Oil Rate (bbl/d) 162 304 340

boe/d (6:1) 1,160 840 1,470Gas Price ($C/GJ) $3.00 $3.00 $3.00Oil Price ($US/bbl) $50.00 $50.00 $50.00

Price ($/boe) $25.39 $35.02 $29.41Crown Royalty 5% 5% 5%GORR 10% 2% 3%

Royalty ($/boe) $3.81 $2.45 $2.351st Mo Op. Cost ($/boe) $3.76 $2.30 $1.96Midstream ($/boe) $1.40 $1.03 $1.25

Transport ($/boe) $2.04 $3.06 $2.461st Month Netback ($/boe) $14.39 $26.19 $21.39

Cashflow/Month ($M) $500 $660 $940

Prices ($Cdn GJ, $US WTI): $3.00$50.00

Western SimonetteHistorical Avg Well

Simonette Wells Initial 30 Day Comparison

IMPROVED MONTNEY NETBACKS

www.cequence‐energy.com1400, 215 9TH AVE S.W.   CALGARY AB  T2P 1K3 PHONE: 403‐229‐3050   FAX: 403‐229‐060

Contacts:Todd BrownCEO tbrown@cequence‐energy.com

David GillisEVP & CFOdgillis@cequence‐energy.com

TSX:CQE