Positioned for Gas Growth

TSX:CQE 1

September, 2016

Forward‐Looking Information and Definitions

TSX:CQE 2

Summary of Forward‐Looking Statements or Information

Certain information included in this presentation constitutes forward‐looking information under applicable securities legislation. This informationrelates to future events or future performance of the Company. Investors are cautioned that reliance on such information may not be appropriatefor making investment decisions. Many factors could cause the Company’s actual results, performance or achievements to vary from thosedescribed herein. The forward‐looking information contained in this presentation is expressly qualified by this and other cautionary statements setforth in the continuous disclosure record of the Company.For a complete description of the forward‐looking statements or information and the definitions used in this presentation, see slide 24 "Forward‐Looking Statements or Information and Definitions."The reporting and the measurement currency is the Canadian dollar. For the purpose of calculating unit costs, natural gas is converted to a barrelof oil equivalent (“boe”) using six thousand cubic feet of natural gas equal to one barrel of oil unless otherwise stated. The term barrel of oilequivalent (boe) may be misleading, particularly if used in isolation. A boe conversion ratio for gas of 6 Mcf:1 boe is based on an energyequivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead. This Value Ratiois significantly different from the energy equivalency ratio of 6:1 and using a 6:1 ratio would be misleading as an indication of value.NON‐GAAP MEASUREMENTS

References are made to terms commonly used in the oil and gas industry, including operating netback, net debt, 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 boerevenue 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.Net debt is a non‐GAAP term 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. Funds flow from (used in) operations per share is calculated using the same weighted average number of shares outstanding used in the calculation of comprehensive income (loss) per share.

Corporate Overview

TSX:CQE 3

Trading Symbol TSX: CQE

H1 2016 average production 9,040 boepd

2016 production guidance 8,500 boepd

52‐week trading range $0.23 ‐ $.64

Shares outstanding 211 MM

Insider ownership (1) 6.5%

Market capitalization (2) $57 MM

Net debt ‐ June 30, 2016(3)   $73 MM

Senior Unsecured Notes (maturing October 2018) (4) $60 MM

2016 hedges (50% volume) $2.60/GJ

Reserves P + P, December 31, 2015 126 MMBoe

(1) Insider ownership is 32% including private equity shareholder represented on the board.(2) Based on Cequence stock price of $0.27(3) Net debt is comprised of $60 MM of Senior notes and $13 MM of working capital deficiency(4) CPPIB is the holder of the senior unsecured notes.

2016 Strategy and Accomplishments

TSX:CQE 4

Reduced cost structure: G&A expenditures down 17%  YTD from prior year (1) and expect 32% reduction by Q4 2016 Operating cost improvements 23% reduction in Q2 2016 operating costs per boe from 2015 (2)

Improved Montney performance: Simonette Montney design changes and netback initiatives have improved economics 16‐33 six month cumulative production exceeds historical results by 60% for natural gas 190% for condensate 

Stable Balance Sheet: $60 MM term debt (Oct 2018) Senior Credit facility extended to May 2017

Commercial Inventory under current strip prices

Continue to pursue strategic M&A transactions

(1) Refers to G&A expenses, prior to restructuring charges of $3,728 and $4,489 for the six months ended June 30, 2016 and 2015, respectively(2) Prior to midstream capital fees

Strategic Advantage

TSX:CQE 5

British Columbia Alberta

GRANDEPRAIRIE

Deep Basin 

SIMONETTE PROJECT

CANADAUSA

Large established reserves (1): 126 MMboe proved plus probable (86% gas)

Significant upside: > 3.8 TCF gross (2) of Upper Montneyresource with 150 net unbooked locations (3)

Multi zone targets:  86 sections Montney rights, 150 sections of Cretaceous rights

Oil & condensate: Dunvegan oil and liquid rich Montneywells increasing the liquids weighting

YE 2015 Proved plus probable oil reserves increased by 43% to 17.1 MMbbl (1)

Infrastructure – 120 MMcfd facility & gathering system built.  No material future infrastructure projects required.

Sales optionality: Alliance and NGTL gas pipeline connections established.  

(1) Reserves evaluation by GLJ Petroleum Consultants Ltd. effective December 31, 2015.  Oil reference includes product types of light and medium crude oil, tight oil, and heavy crude oil(2) See Forward‐Looking Information and Definitions for definition of DPIIP and total resource, Upper Montney only.(3) Internal Cequence estimate

Sustainable Cash Cost improvements$5 MM per year savings

TSX:CQE 6

23 % decrease in YoY operating expenses before capital midstream fees

Performance tested alternative chemical suppliers.   ½ treating cost for sour wells (200 to 1000 

ppm)

Impact $0.30/mcf lower cost on 15 MMcfd

Western Simonette wells low H2S (<15 ppm)

Operational structure ‐ Focused Operating shift changes

Improved mechanical competency

Coordinated trucking with industry

Reduced cost $0.30/boe

CQE 100% owned water disposal well Drilled, completed, tested Q3 – 675 m3/d

Lower trucking & disposal cost

Reduce operating cost $0.60/boe

Full impact will be realized Q4 2016

$/boeQ2 2016

Q2 2015 Change

Operating Expense, prior tomidstream costs $6.85 $8.91 ($2.06)

Capital midstream fees(1) $1.28 $0.08 $1.20

Total operating expenses $8.13 $8.99 ($0.86)

(1) Includes capital midstream fees only. Cequence began paying a capital midstream fee at its Simonette property on June 17, 2015 upon closing of the sale of 50% of its Simonette gas plant.  The 2015 Midstream transaction also provided for the joint construction of the Simonette refrigeration plant and connection to NGTL.

Simonette Montney – Large Recognized Inventory

TSX:CQE 7

121 MMboe proved plus probable booked reserves (1) Stacked horizons: Dunvegan, Gething, Falher, 

Wilrich, Montney

3.8 TCF gross Montney resource in place  (2) PDP: 12.3 Mboe TP: 47.5 Mboe 45 gross (42 net) wells 2P: 97.4 Mboe 75 gross (69.5 net) wells 2P + Best Estimate contingent: 94 (87) wells Booked at 400 m interwell spacing. 

16‐33 Montney: IP 180 day 1,110 boed, 260 bbl/d condensate

3,050 m lateral, 70 frac stages, 3,150 tonnes sand, cemented liner 21 sections of analogous Western lands (50 

potential net wells at 300 m spacing (3)

XTO activity and licenses adjacent to CQE will de‐risk southwest lands

CQE 16‐33

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

(1) Reserves evaluation by GLJ Petroleum Consultants Ltd. effective December 31, 2015(2) See Forward‐Looking Information and Definitions for definition of DPIIP and total resource, Upper Montney only.(3) Internal estimate based on 300m interwell spacing, 26 locations are included in the reserves evaluation by GLJ at December 31, 2015.

Cequence 16‐33 Montney Gas Well Improved Results

TSX:CQE8

16‐33‐61‐27W5: 180 day comparison to 2014/15 average 1.6 times produced gas (1 bcf vs 0.6 bcf) 2.9 times cumulative condensate (50 Mstb vs 17 Mstb) Cumulative 6 month yield 50 bbl/mmcf C5+

Trending above company 7 bcf type curve (1)

Strong casing pressures above 1,100 psi (Flowing up tubing)

Less than 15 ppm H2S: $0.30/mcf lower treating cost than 2014/2015 program

Payout less than 2 years under strip pricing (2)

1. Type curves are internally generated, see definitions on page 242. August 4th strip pricing (Cal 17 AECO $2.83 and WTI USD/bbl of $46.25)

16‐33: West Area Higher 1st Year Netback

TSX:CQE 9

C5 Yield is double the historical average well(1)

West Montney Area lower GORR (1‐3% vs 8‐12%)

$2.00/boe lower operating cost with improved cost structure and low H2S treating

Midstream fee charged for raw gas volumes only

Transport(2) costs higher for associated C5 production

(1) Yield represents field condensate only.  Another 3‐5 bbl/MMcf of C3+ is recovered at the Simonette plant(2) Illustrated transportation cost is $0.20/GJ gas on NGTL and $6/bbl for liquids trucking and pipeline tariff at Lator terminal

Historical Average Well

16‐33 West Simonette

C5 Yield (bbl/mmcf) 25 50Gas Price ($C/GJ) $3.00 $3.00Oil Price ($US/bbl) $50.00 $50.00

Price ($/boe) $26.47 $30.84Crown Royalty 5% 5%GORR 10% 3%

Royalty ($/boe) $3.97 $2.471st Yr Op. Cost ($/boe) $4.19 $2.15Midstream ($/boe) $1.50 $1.32

Transport ($/boe) $2.13 $2.60

1st Year Avg Rate (boed) 540 840

1st Yr Netback ($/boe) $14.68 $22.3150+% uplift 

Montney Drilling & Completion CostsDriving Improved Performance

TSX:CQE10

Implemented Montney drilling design changes saving time and providing flexibility

Simplified drilling path Shallower intermediate casing depth Cemented production casing (less hole conditioning) 6,100 m in 34 days as a “one off”

Increased completion effectiveness Longer laterals with 2 x tighter frac spacing Full diameter production casing – better mitigation Significant completion & production flexibility without 

milling operations

New design delivered 30% lower cost per meter compared to 2014 program.

Efficiencies for continuous pad drilling have not been incorporated

On lease tie‐in $0.3 MM/well

*2014 wells in solid lines

16‐33 fastest well to drill out of ICP

15‐28 stages0.5 t/m

26 stage1.0 t/m

0

1000

2000

3000

4000

5000

6000

70000 2 4 6 8 10 12 14 16 18 20 22 24 26 28 30 32 34 36 38 40 42 44 46 48 50

Dep

th (T

MD m

)

Days from Spud

Montney Drilling Curves

Improved Commercial Impact

TSX:CQE 11

(1)  Assumes 30 Bbls/MMcf of NGL’s and condensate Includes 5% GORR, Opex $2.50 per Boe incremental, $0.27/mcf midstream capital Incorporates go forward operating cost savings for H2S, water, trucking Assumes NGTL transport 2017 onward of $0.20/GJ(2) Internal estimate based on 300m interwell spacing, 26 locations are included in the reserves evaluation by GLJ at December 31, 2015.

Mean booked well inventory length increased 25% to 2,500 m Operating cost initiatives captured in economics Western lands have strong value – 50 potential net locations (2)

Additional capital improvements can be realized

2,500 m Mean Well (1)

16‐33 ‐ 3% GORR, 50 bbl/MMcfd C5

Length (m) 2,500 3,050

Total ($MM) $7.7 $8.6

IP30 Production Rate (MMcf/d) 6.0 6.8Reserves (MBOE) 1,120 1,400ORGIP (Bcf) 6.0 7.0

F&D ($/BOE) $6.88 $6.141st Yr Netback ($/boe) $17.70 $22.30Recycle Ratio  2.6 3.6ROR (%) 35% 68%Payout (Years) 2.5 1.5NPV10% ($M) $4.5 $8.8Breakeven Gas Price ($C/GJ)               (at $50.00 WTI/Bbl)

$1.90 $1.05

Production Efficiency ($/boed‐365) $11,600 $10,200

Parameters

Costs (Drill, Complete, Equip)

Drilling Results

Economic Indicators

$50 WTI, $3.00/GJ CDN 

‘17 Strip Prices

Simonette/Karr Dunvegan – Light Oil Development

TSX:CQE 12

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

Dunvegan Oil play at Simonette is analogous to the Karr Oil Pool

9 gross (7.5 net) sections identified with oil development potential in Dunvegan  sand

60 mmbbls OOIP (1) net to Cequence.  41oAPI oil

28 gross (24 net) locations with average 1,900 meter lateral length.

Solution gas gathered to Cequence/KANATA 13‐11 Gas Plant

Existing 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 24.

Simonette Dunvegan Oil

TSX:CQE 13

(1) Reserves evaluation by GLJ Petroleum Consultants Ltd. effective December 31, 2015.(2) Proved undeveloped and probable locations are derived from the Company’s December 31, 2015 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.

CQE 7‐11 production to end of July 2016 (1 year) 80 Mbbl and 440 MMcf gas  IP 365: 220 bbl/d, 420 boe/d Less than 2% watercut

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

2,000 m well$4.5

IP365 Production Rate (bbl/d) 240Reserves (MBOE) 540

F&D ($/BOE) $8.331st Yr Netback ($/boe) $22.90Recycle Ratio  2.7ROR (%) 75%Payout (Years) 1.3NPV10% ($M) $3.9Breakeven Oil Price ($US/bbl)               (at $3.00/GJ Gas)

$29.00

Production Efficiency ($/boed‐365) $10,800

$50 US WTI, $3.00/GJ CDN Costs (Drill, Complete, Equip) ($MM)

Drilling Results

Economic Indicators

Simonette Egress – Major Facility Capital SpentOptionality on both major gas systems in Alberta

TSX:CQE 14

120 MMcfd refrigeration plant (50% WI) on‐stream Jan 2016.  Currently 60% available capacity

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

Dual connection to NGTL and Alliance pipeline systems effective April 1, 2016 NGTL transport $0.20/GJ to AECO

CQE Alliance contracts end March 31, 2017

10,000 GJ firm on NGTL effective July 1, 2016 

200 MMcfd meter capacity

All major gathering system built.  Padsitesare built or acquired for drilling inventory.  ½ cycle economics applicable

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

CQE Land

Alliance PipelineGathering System

TCPL PipelinePembina Pipeline

R23W5R1W6 R24R25R26R27R2

T60

T61

T62

T63

T64

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

6 miles

CQE 9‐10Field Compressor

Alliance/Aux SableDeep Cut PlantChicago, Illinois

Pembina LatorTruck Terminal

Proposed Pembina Simonette Terminal

Cequence Growth – A Scenario

TSX:CQE 15

A measured growth profile of 11% CAGR can be achieved with capital expenditures limited to EBITDA beginning in 2017

Accelerated volume growth achievable with higher capitalization

Profile includes 85 Montney wells and 10 Dunvegan oil wells

No material facility expenditures are included until 2020

Maintaining current production of 9,000 boepd in 2017 requires approximately 3 Montney wells to be drilled1 4 5 7 9 1111 11 12 12 12New Wells

• Company generated forecast• August 4th strip pricing (Cal 17 AECO $2.83 and WTI USD/bbl of $46.25)• Montney drilling incudes 40 wells using 85% of 16‐33 type curve and 45 wells using the 2,500 mean well type 

curve detailed on page 11.• Montney capital cost of $8.5 million/well, $5 MM/well Dunvegan oil, $3 MM/year miscellaneous• Total operating costs in period (including midstream fees) average $8.10/boe• G&A costs in period average $6.5 million/year

Hedging

16

Contract Type Volume GJ/d CAD Price

GAS

2016 July 1, 2016 to September 30, 2016 Average Gas Swap 22,500 $2.56/GJ AECO

2016 October 1, 2016 – December 1, 2016 Average Gas Swap 20,000 $2.65/GJ AECO

2017 January 1, 2017 – March 31, 2017 Average Gas Swap 15,000 $2.58/GJ AECO

2017 April 1, 2017 – December 31, 2017 Average Gas Swap 10,000 $2.64/GJ AECO

OIL Volume bbl/d CAD Price

2016 April 1, 2016 – December 31, 2016 Swap 400 $65.35/bbl

2017 January 1, 2017 – December 31, 2017 Swap 100 $65.55/bbl

• 2017 program has been initiated with an expectation to get to 50% of 2017 volumes.

In Summary – Why own CQE?

TSX:CQE 17

RESTRUCTURED: To lean, operational focused team.

IMPROVED COSTS:  17% lower YTD G&A costs with 32% total reduction expected by Q4 2016 Demonstrated improved operating cost structure with leverage to development economics

LARGE RECOGNIZED RESERVES(1) : 126 Mmboe proved probable reserves (86% gas)

RESULTS: Recent Montney well above company type curve(2) for gas and condensate.  (Improved technology)

INFRASTRUCTURE: Major facilities in place with connection to NGTL and Alliance pipelines

STABLE BALANCE SHEET: $60 million of term debt (Oct 2018) and senior credit facility extended to May 2017

TORQUE: to increasing gas prices

(1) Reserves evaluation by GLJ Petroleum Consultants Ltd. effective December 31, 2015. (2) Type curves are internally generated, see definitions on page 24.

Appendix

TSX:CQE 18

Management and Board

TSX:CQE 19

Management Team

Todd Brown – CEOTodd Brown – CEO

Dave Gillis ‐ EVP and CFODave Gillis ‐ EVP and CFO

Dave Robinson ‐ VP Exploration and Chief GeologistDave Robinson ‐ VP Exploration and Chief Geologist

Chris Soby ‐ VP Land and Corporate DevelopmentChris Soby ‐ VP Land and Corporate Development

Erin Thorson ‐ ControllerErin Thorson ‐ Controller

Board of Directors

Don Archibald ‐ ChairmanDon Archibald ‐ Chairman

Peter BannisterPeter Bannister

Rob CookRob Cook

Howard CroneHoward Crone

Brian FeleskyBrian Felesky

Daryl GilbertDaryl Gilbert

Frank MeleFrank Mele

James Gray ‐ Director EmeritusJames Gray ‐ Director Emeritus

Simonette Deep Basin Stack

TSX:CQE 20

Dunvegan 

Falher Bluesky / Gething

MontneyWilrich  

Simonette Upper

CURRENT HORIZONTAL TARGET ZONE

POTENTIAL HORIZONTAL TARGET ZONE

Multiple Zones with Significant Resource Potential at Simonette

TSX:CQE 21

CEQUENCE LAND

6 miles

5‐25 BCF5‐10 MMBBL

5‐24 BCF 5‐24 BCF

5‐25 BCF

30‐60 BCF

Dunvegan GasDunvegan Oil

FalherWilrich

Gething

UpperMontney

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

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 2015Proved + Probable (2)Total Proved2P per share

113

49

67

91

118126

Reserves and Finding Costs – solid growth per share in reserves

TSX:CQE 22

‐$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)

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 Value 2P per shareGLJ Proved + Probable  NPV 10%

$1,004

$854

$482$525

$715

$797

Reserves (MMboe)

Corporate Guidance

2016

Average Production (Boe/d)(1) 8,500

Capital expenditures, net of dispositions (2) $7 MM

Operating and transportation costs per Boe  $11.30

G&A costs per Boe, prior to restructuring charges of $0.60/boe $2.20

Royalties (% of revenue) 6%

Crude oil – WTI (US$/Bbl) $43.00

Natural gas – AECO (Cdn$/GJ) $1.90

Funds flow from operations (3) $2 MM

Annualized fourth quarter 2016 funds flow from operations $12 MM

Net debt and working capital deficiency, December 31, (4) $70 MM

Basic shares outstanding

Natural gas price sensitivity, including hedges +/‐ $0.25/GJ

211 MM

$2.4 MM

(1) Comprised of 85% natural gas and  15% of oil and liquids.(2) Capital expenditures include $14 million of capital expenditures and $7 million of dispositions.  (3) Funds flow from operations is calculated as cash flow from operating activities before  adjustments for decommissioning liabilities.  Includes severance payments of $2 million.(4) Net debt is calculated as working capital (deficiency) less the principal value of the senior notes.

23

Forward‐Looking Statements or Information and Definitions

TSX:CQE 24

Certain statements included in this presentation constitute forward‐looking statements or forward‐looking information under applicable securities legislation. Such forward‐lookingstatements or information are provided for the purpose of providing information about management's current expectations and plans relating to the future. Readers are cautioned thatreliance on such information may not be appropriate for other purposes, such as making investment decisions. Forward‐looking statements or information typically contain statements withwords 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 relatedassumptions; 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; commoditypricing and expected royalties; costs associated with operating in the oil and natural gas business; and future production levels, including the composition thereof. Forward‐lookingstatements 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. TheCompany believes that the expectations 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 which may be identified in thispresentation, assumptions have been made regarding, among other things: the impact of increasing competition; the timely receipt of any required regulatory approvals; the ability of theCompany 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 operatethe 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 andexpand 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 secureadequate 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 whichhave 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 todiffer 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 differmaterially from the forward‐looking statements or information. The material risk factors affecting the Company and its business are contained in the Company's Annual Information Formwhich 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 anyforward‐looking statements or information, whether as a result of new information, future events or otherwise unless required by applicable securities laws. The forward‐lookingstatements or information contained in this presentation are expressly qualified by this cautionary statement.

Discovered Petroleum in Place ("DPIIP") 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 petroleuminitially‐in‐place includes production, reserves and contingent resources; the remainder is unrecoverable. "Contingent Resources" are defined in COGEH as those quantities of petroleumestimated to be potentially recoverable from known accumulations using established technology or technology under development, but which are not currently considered to beeconomically recoverable due 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 early evaluation stage. The ContingentResources 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 becommercially viable to produce any portion of the resources except to the extent identified as proved or probable reserves.

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

TSX:CQE 25

www.cequence‐energy.com3100, 525 ‐ 8th Avenue SW   Calgary AB  T2P 1G1Phone: 403‐229‐3050   Fax: 403‐229‐0603

Contacts:Todd BrownCEO tbrown@cequence‐energy.com

David GillisEVP & CFOdgillis@cequence‐energy.com