POSITIONED FOR LIQUIDS RICH GAS GROWTH

POSITIONED FOR LIQUIDS RICH GAS GROWTH September 2017 1

Summary of Forward Looking Statements or Information FORWARD LOOKING INFORMATION AND DEFINITIONS 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 such information 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 is 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 is converted to 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 term barrel of oil equivalent (boe) may be misleading, particularly if used in isolation. A boe conversion ratio for gas of 6 Mcf:1 boe is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead. This value ratio is significantly different from the energy equivalency ratio of 6:1 and using a 6:1 ratio would be misleading as an indication of value. See slide 21 for additional advisories. NON GAAP MEASUREMENTS 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. Operating netback equals per boe revenue less royalties, operating costs and transportation costs. Management utilizes this measure to analyze the operating performance of its assets andoperating 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 for decommissioning liabilities expenditures and net changes in non cash working capital. The Company evaluates its performance based on earnings and funds flow from (used in) operations. The Company considers funds flow from (used in) operations a key measure as it demonstrates the Company s ability to generate the cash flow necessary to fund future growth through capital investment and to repay debt. The Company s calculation of funds flow from (used in) operations may not be comparable to that reported by other companies. Operating netback is not defined by IFRS in Canada and is referred to as a non GAAP measure. Operating netback equals per boe revenue less royalties, operating costs and transportation costs. Management utilizes this measure to analyze operating performance of its assets and operating areas, compare results to peers and to evaluate drilling prospects. TSX:CQE 2

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 TSX:CQE 3

OVERVIEW Trading Symbol Q2 2017 average production 52 week trading range Shares outstanding TSX: CQE 8,502 boe/d $0.13 $0.37 246 MM Insider ownership (1) 10.5% Market capitalization (2) Net debt June 30, 2017 (3) $34 MM $68 MM Net debt/funds Flow H1, 2017 (4) 2.4X 2017 natural gas hedges (approximately 60% of total volume) Reserves P + P, December 31, 2016 $2.78/GJ 136 MMBoe (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 4

STRATEGY Lower Cost Structure Q2 G&A expenditures: down by 39% year overyear Q2 operating costs: 7% reduction to $7.53/boe Improved Well Performance Montney design changes and netback initiatives have improved economics Dunvegan oil results above analog average Large Recognized Inventory 87.5 net booked Montney locations Expanding Dunvegan inventory Infrastructure in place. No material plant or pipe costs required Stable Balance Sheet $60 MM subordinated term debt (Oct. 2018) $20 MM undrawn senior credit facility $10 MM raised in Oct. 2016 private placement TSX:CQE

2017 GUIDANCE Revised Year Ended December 31, (000 s, except per share and per unit references) 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 (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. TSX:CQE 6

CQE 16 33 2017 drills SIMONETTE MONTNEY Western area Higher liquids (35+ bbls/mmcf) 2.7% average GORR MULTIPLE ZONES Stacked horizons: Dunvegan, Gething, Falher, Wilrich, Montney BIG RESOURCES All 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. TSX:CQE 7

CEQUENCE SIMONETTE WEST AREA CHARACTERIZATION Double the condensate rate vs the historical type curves Condensate rate 2X historical Higher netback production LIQUIDS RICH Liquids sales 98% high value pentanes plus COST EFFICIENT Less than 15 ppm H 2 S: $0.30/mcf lower treating cost than 2014/2015 program EXPANDED INVENTORY West area inventory unbooked 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. TSX:CQE 8

DRIVING IMPROVED PERFORMANCE 0.5 t/m 0.5 t/m 1.0 t/m 1.0 t/m 1.2 t/m 15 28 stages 26 stages 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 TSX:CQE 9

COMMERCIAL INVENTORY $50 WTI, $3.00/GJ CDN Parameters 2,500 m Mean Well (1) 2017 West Montney 16 33 3% GORR (50 bbl/mmcfd C5) Length (m) 2,500 2,850 3,050 Costs (Drill, Complete, Equip) Total ($MM) $7.7 $8.0 $8.6 Drilling Results IP30 Production Rate (MMcf/d) 6.0 3.2 6.8 Reserves (MBOE) 1,120 845 1,500 Economic Indicators F&D ($/BOE) $6.88 $9.47 $5.73 1st Yr Netback ($/boe) $17.70 $28.30 $22.30 Recycle Ratio 2.6 3.0 3.9 ROR (%) 35% 30% 70% Payout (Years) 2.5 2.6 1.3 NPV10% ($M) $4.5 $3.8 $10.0 Breakeven Gas Price ($C/GJ) (at $50.00 WTI/Bbl) $1.90 $1.25 $1.01 Production Efficiency ($/boed 365) $11,600 $16,360 $9,600 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 (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. TSX:CQE 10

KARR ANALOG Karr Type Log 6 6 Simonette Type Log CQE 10 9 SIMONETTE DUNVEGAN OIL PLAY Net Pay 9m 15% Ø Net Pay 10m 15% Ø Dunvegan Gas Pool Dunvegan Oil Pool SIMONETTE Dunvegan Gas Pool 9 gross (7.5 net) sections identified with oil development 40 o 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 1. Original oil in place (OOIP) is equivalent to DPIIP for purposes of this presentation. See page 21. TSX:CQE 11

$50 US WTI, $3.00/GJ CDN 2,000 m well 2,000 m well Costs (Drill, Complete, Equip)($MM) $4.5 $4.0 IP365 Production Rate (bbl/d) 220 220 Reserves (MBOE) 540 540 SIMONETTE DUNVEGAN LIGHT OIL (1) July 15 treater & Pembina connection Economic Indicators F&D ($/BOE) $8.30 $7.40 1st Yr Netback ($/boe) $27.74 $27.74 Recycle Ratio 3.3 3.7 ROR (%) 80% 100%+ Payout (Years) 1.2 1.0 NPV10% ($M) $4.3 $4.8 Breakeven Oil Price ($US/bbl) (at $3.00/GJ Gas) $23.40 $21.35 Production Efficiency ($/boed 365) 10,150 9,000 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) 2,000 bbl/d facility built with solution gas gathering to CQE/KANATA Simonette plant Gas to 13 11 5 7 Battery 2,000 bbls/d 1,150 Hp Compressor 2 3 Net locations planned Q4 2017/Q1 2018 July 2017: Connection to Y battery & Pembina Existing Gas Line Future Oil/Water Line TSX:CQE (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. 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. 12

Cequence Alliance Meter Station Capacity 120 MMcf/d Pembina Lator Truck Terminal CQE 9 10 Field Compressor SIMONETTE EGRESS MAJOR INFRASTRUCTURE BUILT Proposed Pembina Simonette Terminal Alliance/Aux Sable Deep Cut Plant Chicago, Illinois NGTL meter station March 2016 200 MMcf/d 13 11 Facility Curr. capacity Compression 100 MMcf/d Refrigeration 120 MMcf/d Cond stabilization 4,500 bpd 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 TSX:CQE 13

HEDGING 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 $3.01/GJ AECO OIL Volume bbl/d Price Cdn$ 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

WHY OWN CQE? Improved Costs Large Recognized Reserves (2) Improved operating cost structure with leverage to development economics YTD 34% lower G&A costs (1) 136 MMboe proved + probable reserves (86% gas) Results Encouraging high liquid West Montney Lands Excellent Dunvegan oil results with large inventory Infrastructure Major facilities in place with connection to NGTL and Alliance pipelines Torque Low break even gas price Higher liquids production Restructured Lean operations focused team (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. TSX:CQE 15

APPENDIX TSX:CQE 16

MANAGEMENT AND BOARD Management Team Todd Brown CEO Dave Gillis EVP and CFO Dave Robinson VP Ex and Chief Geologist Chris Soby VP Land and Corporate Development Erin Thorson Controller Board of Directors Don Archibald Chairman Peter Bannister Todd Brown Howard Crone Brian Felesky Daryl Gilbert Frank Mele TSX:CQE 17

SIMONETTE DEEP BASIN STACK Dunvegan Falher Wilrich Bluesky / Gething Montney Simonette Upper CURRENT HORIZONTAL TARGET ZONE POTENTIAL HORIZONTAL TARGET ZONE TSX:CQE 18

MULTIPLE ZONES WITH SIGNIFICANT RESOURCE POTENTIAL AT SIMONETTE 2,400m 2,500m 2,700m 2,800m 2,950m 3,100m Zone Dunvegan Gas Dunvegan Oil Falher Wilrich Total Resource Potential/Sec (1) 5 25 Bcf 5 10 MMbbl 5 24 Bcf 5 24 Bcf Gething 5 25 Bcf Upper Montney 30 60 Bcf TSX:CQE (1) See Forward Looking Information and Definitions for definition of total resource

RESERVES AND FINDING COSTS SOLID GROWTH PER SHARE IN RESERVES $16.00 $14.00 $12.00 $10.00 $8.00 $6.00 $4.00 $2.00 FD&A ($/Boe) 140 120 100 80 60 40 Reserves (MMboe) 118 126 113 91 67 49 0.7 0.6 0.5 0.4 0.3 0.2 1200 1000 800 600 400 2P Reserve Value ($MM) $1,004 $797 $715 $525 $854 $482 6 5 4 3 2 $0.00 $2.00 20 0.1 200 1 $4.00 2010 2011 2012 2013 2014 2015 Proved + Probable (Incl FDC) 0 2010 2011 2012 2013 2014 2015 Proved + Probable (2) Total Proved 2P per share 0.0 0 2010 2011 2012 2013 2014 2015 Reserve Value 2P per share GLJ Proved + Probable NPV 10% 0 TSX:CQE 20

FORWARD LOOKING STATEMENTS OR INFORMATION AND DEFINITIONS 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 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 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 information concerning Cequence in this presentation may include, but are not limited to, statements or information with respect to: guidance, forecasts and related assumptions; expected production growth and cash flow growth and the respective timing thereof; capital spending; expected resource potential and future reserves; hedging objectives; business strategy 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 composition thereof. Forward looking statements or information are based on a number of factors and assumptions which have been used to develop such statements and information but which may prove to be incorrect. The Company believes that the expectations reflected in such forward looking statements or information are reasonable; however, undue reliance should not be placed on forward looking statements because the Company can give no assurance that such expectations will prove to be correct. In addition to other factors and assumptions which may be identified in this presentation, assumptions have been made regarding, among other things: the impact of increasing competition; the timely receipt of any required regulatory approvals; the ability of the Company to obtain qualified staff, equipment and services in a timely and cost 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; the ability 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 reserves through acquisition, development or exploration; the timing and costs of operating the Company s business; the ability of the Company to secure adequate product transportation; future oil and natural gas prices; currency, exchange and interest rates; the regulatory framework regarding royalties, taxes and environmental matters; and the 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 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 uncertainties which 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 factors affecting 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 to update publicly or revise any forward looking statements or information, whether as a result of new information, future events or otherwise unless required by applicable securities laws. The forward 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 Canadian Oil 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. Contingent Resources are defined in COGEH as those quantities of petroleum estimated to be potentially recoverable from known accumulations using established technology or technology under development, but which are not currently considered to be economically recoverable due to one or more contingencies. 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. The Contingent Resources estimates and the DPIIP estimates are estimates only and 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 the resources 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 to production history from analogous Montney developments located in close proximity. Such type curves and well economics are useful in understanding management's assumptions of well performance in making investment decisions in relation to development drilling and for determining the success of the performance of development 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 curvespresented; however, there is nocertaintythatcequence will ultimately recover such volumes from the wells it drills. TSX:CQE 21

SUSTAINABLE COST IMPROVEMENTS 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. TSX:CQE 22

IMPROVED MONTNEY NETBACKS Simonette Wells Initial 30 Day Comparison Historical Avg Western Simonette Well 2017 Montney 16 33 C5 Yield (bbl/mmcf) 27 95 50 Gas Rate (MMcf/d) 6,000 3,200 6,800 Oil Rate (bbl/d) 162 304 340 boe/d (6:1) 1,160 840 1,470 Gas Price ($C/GJ) $3.00 $3.00 $3.00 Oil Price ($US/bbl) $50.00 $50.00 $50.00 Price ($/boe) $25.39 $35.02 $29.41 Crown Royalty 5% 5% 5% GORR 10% 2% 3% Royalty ($/boe) $3.81 $2.45 $2.35 1st Mo Op. Cost ($/boe) $3.76 $2.30 $1.96 Midstream ($/boe) $1.40 $1.03 $1.25 Transport ($/boe) $2.04 $3.06 $2.46 1st Month Netback ($/boe) $14.39 $26.19 $21.39 Cashflow/Month ($M) $500 $660 $940 Recent Results Increased netbacks C5 rate double historical average well (1) GORR 1 3% vs. 8 12% Op Costs $2.00/boe lower (improved cost structure, lower H2S content) Midstream inlet raw gas charge Transport higher for C5 production (2) Prices ($Cdn GJ, $US WTI): $3.00 $50.00 (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. TSX:CQE 23

www.cequence energy.com 1400, 215 9 TH AVE S.W. CALGARY AB T2P 1K3 PHONE: 403 229 3050 FAX: 403 229 060 Contacts: Todd Brown CEO tbrown@cequence energy.com David Gillis EVP & CFO dgillis@cequence energy.com TSX:CQE