March 2013 CIBC Energy Conference Toronto - April 16 - 17, 2013

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.

Total resources is that quantity of petroleum that is estimated to exist originally in naturally occurring accumulations. It includes that quantity of petroleum that is internally estimated, at a given date, to be contained in known accumulations, prior to production, plus those quantities in accumulations yet to be discovered.

Original Oil in Place (OOIP) is equivalent to Discovered Petroleum Initially-In-Place (DPIIP). DPIIP, as defined in the Canadian Oil and Gas Evaluations Handbook (COGEH), is 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 DPIIP includes production, reserves and contingent resources; the remainder is unrecoverable.

Original Gas in Place (OGIP) is equivalent to Discovered Petroleum Initially-In-Place (DPIIP). DPIIP, as defined in the Canadian Oil and Gas Evaluations Handbook (COGEH), is 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 DPIIP (ORGIP) includes production, reserves and contingent resources; the remainder is unrecoverable.

OOIP and OGIP estimates are internally estimated and prepared by a qualified reserves evaluator.

2

Cequence is focused in the Deep Basin of Alberta

3

USA CANADA

Peace River Arch/NE BC - 2012 Production: 1,800 boe/d

Deep Basin - 2012 Production: 7,100 boe/d

Deep Basin

SIMONETTE

Ansell/Edson Wilrich Project

High quality, operated asset base in multi-zone, liquids-rich gas areas

Simonette winter drilling program has expanded the extent and quality of our large resource base in multiple formations

Emerging new Wilrich resource play at Edson

Control 170,000 net acres within the Deep Basin

Corporate Profile

4

Trading Symbol TSX: CQE

2013 First Half Production Guidance 10,000 boepd

52-week trading range $0.88-$2.05

Shares outstanding (3) 211 million

Insider ownership 12% FD

Market capitalization (1) $360 million

December 31, 2012 net debt (2) $46 million

Bank line $100 million

(1) Based on Cequence stock price of $1.70 (2) Net debt is calculated as net working capital less commodity contract asset and liabilities and demand credit facilities and excluding other liabilities. (3) Pro forma the issuance of 10.3 million common shares pursuant to the acquisition of Montney Assets expected to close April 15, 2013.

Recent Highlights

5

Simonette winter drilling success will generate a step-change in production in the second quarter of 2013

2012 reserves increased 32% to 91 mmboe with a value of $796 million

Strong F,D&A - $10.57 per boe Proved plus Probable including FDC

Top quartile cost structure- Q4 total cash costs $10.65 per boe

Recently announced an acquisition to consolidate our Montney land position at Simonette to total 89 net sections

2012 Reserves and Finding Costs

$0.00

$2.00

$4.00

$6.00

$8.00

$10.00

$12.00

$14.00

$16.00

2010 2011 2012

FD&A ($/boe)

Proved + Probable (Incl FDC)

6

0

20

40

60

80

100

2010 2011 2012Proved + Probable Total Proved

49

91

67

0

100

200

300

400

500

600

700

800

900

2010 2011 2012

Reserve Value ($MM)

Proved + Probable GLJ Dec 31, 2012

$525

$715 $797

Reserves (MMBoe)

FD&A costs were top quartile

Recycle ratio is 1.6 times using Q4 operating netback of $16.45 per boe

Replaced 820% of production in 2012 with proved plus probable reserves

20.30

19.37

17.38 16.76

14.99

14.08 14.21

12.84 12.58

13.88

11.87

10.65

10

15

20

25

0

2,000

4,000

6,000

8,000

10,000

12,000

Natural Gas Oil & NGL Cash Costs*

8,895

Corporate Production and Cash Costs

7

$/b

oe

bo

e/d

9,464 8,879

9,833

9,125

8,185

7,485

4,619

3,197

2,444

8,660 8,951

*Operating cost, transportation, G&A and Interest

Simonette Infrastructure

8

Cequence Alliance Meter Station Capacity 120 mmcf/d

Trilogy Plant CQE W.I. = 25% Capacity 10 mmcf/d

9-10 Field Compressor

13-11 Compressor Station

To Aux Sable Deep Cut Plant Chicago, Illinois

Keyera Processing Facility Capacity 153 mmcf/d

6 miles 3D Seismic Coverage

PHASE 4 FACILITY EXPANSION • COMPRESSION AND CONDENSATE

STABILIZATION

Control 220 gross operated sections (avg. 75% W.I) with excellent land tenure

Cequence operates its facilities at Simonette and delivers raw gas to the Alliance Pipeline for processing at the Aux Sable Deep Cut plant in Chicago

Q4 2012 operating costs are $3.81 per boe resulting in a field netback of $20.60

Phase 4 facility expansion expected startup – April 2013

9

5-25 BCF

5-24 BCF 5-24 BCF

5-25 BCF

30-60 BCF

Dunvegan

Falher

Wilrich

Gething

Upper Montney

Zone Total Resource Potential/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

6 miles

Multiple Zones with Significant Resource Potential

10

6 miles

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

Simonette Montney – Large Scale Resource Play

Conoco cased well

Exxon cased well

Exxon cased well

Petrobakken cased well

3-18 test rate 12.9 mmcfd+ liquids @ 1,775 psi FCP

Testing

Montney Gas/Condensate trend

Three wells drilled in Q1 confirm the extent and quality of this large scale resource play

Up to 150 meters of siltstone to very fine sandstone reservoir

55 MMBOE Proved plus Probable booked with 68 net locations

Recently announced the acquisition of joint Donnybrook acreage giving Cequence approximately 69 net sections in gas/condy trend at an average 40 bcf of total resource per section (1)

Approximately 260 remaining total potential horizontal locations assuming quarter section spacing

Liquids yield (C3+) averages 30 bbls/mmcf (70% condensate)

Oil Prone trend developing in North Simonette

Competitor drilling currently de-risking Cequence land

20 net sections in potential oil trend

Donnybrook Lands

Montney Gas/Condensate Working Model vs. Simonette gas wells

11

0

1000

2000

3000

4000

5000

6000

7000

8000

9000

10000

11000

12000

0 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24

Pro

du

cin

g D

aily

Gas

Rat

e (

mcf

/d)

Months on Production

2-22-61-27

1-31

04-04

01-11-061

09-25

05-35

13-22

10-16

3-18

Average Well Production

CQE Simonette Model

RESERVES

CURRENT MODEL

5.0 BCF raw natural gas 100 MBbl Condensate

50 MBbl Propane/Butane

PRODUCTION

IP YEAR 1 AVERAGE

5.5 mmcfd 110 bpd C5+ 55 bpd C3/C4 1,100 boepd

2.9 mmcfd 63 bpd C5+

30 bpd C3/C4 550 boepd

0

5,000

10,000

15,000

20,000

1.00 2.00 3.00 4.00 5.00 6.00 7.00

3.0 bcf + NGL's 5.0 bcf + NGL's 7.0 bcf + NGL's

Flat AECO Gas Price ($/mmbtu)

12

Montney Half Cycle Economic Sensitivity to Flat Gas Price and Recoverable Gas in Place per Well

Net NGL Yield: 30 Bbl/MMcf C3+ Capital: $7.5 MM Oil Price: $90/bbl WTI

(1) See Forward-Looking Information and Definitions for definition of ORGIP (2) Without GORR * Oil $90/bbl, C3 $31.5/bbl,C4 $70/bbl, C5+ $95/bbl

NP

V 1

0%

BT

($ M

)

Montney Drilling and Completion Costs

4300

4550

4800

5050

5300

5550

5800

0

2000

4000

6000

8000

10000

12000

Completion Cost Drill & Case Cost MD

2010 2011 2012 2013

13

Dri

ll &

Co

mp

leti

on

Co

sts

$M

Met

ers

dri

lled

Most recent wells have longer laterals (2,400 m+) and more frac stages 24+

Winter 2012/13 drilling costs declining while wellbore length increasing

Long term target - $7.5 MM per well (drill, complete & tie in)

Full pad development will offer significant future capital cost savings

* 8-21 costs contain original well combined with re-drill 9-21 completion costs

Target $7.5 MM (D,C,TI)

Montney Drilling Time Comparison

14

0

500

1000

1500

2000

2500

3000

3500

4000

4500

5000

5500

6000

0 5 10 15 20 25 30 35 40 45 50 55

CQE Simonette Winter 2011/12 (7 wells) Resthaven Shortest Drill Time Wapiti Shortest Drill Time

CQE Simonette Winter 2012/13 (4 wells) Resthaven Average (19 wells) Wapiti Average (12 wells)

Resthaven avg. 55 days/4922m

Days from spud

Mea

sure

d D

epth

(m

)

The Simonette area offers efficient penetration rates compared to other Deep Basin Montney areas

Cequence winter 2012/13 wells average 500 meters longer and are 25% faster to drill than previous year

Faster penetration equates to lower capital cost

*Information compiled from Canadian Discovery Frac Data Base and public records

Wapiti avg. 49 days/4305m

Winter 2012/13 - Longer wells/ fewer drilling days

Simonette Dunvegan Oil, and Gas/Condensate Play

16-2 well tested above the model rate at 16.4 mmcf/d plus liquids at 2,380 psi FCP

Resthaven pool is highly productive in the Dunvegan formation from 10 existing horizontals

Cequence has mapped 22 potential locations on 11 net existing sections along gas and oil trend

Up to 25 BCF/sec resource potential

15

Simonette oil pool

42º API

Resthaven gas/condensate pool

6 miles

Oil prone

16-2 HZTL test rate 16.4 mmcf/d plus liquids @ 2,380 psi FCP

Current Production Model: IP rate - 4.5 MMCF/D Reserves – 4.0 bcf and 50-150 Bbl/mm NGL

Simonette Falher Trends – New Discovery

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KAKWA Falher C Channel Pressure: 3950 psi (27216 kpa) Depth: 2400 m (7891 ft) Gradient: 0.5 - 0.55 psi/ft OGIP: 12 Bcf/Section (20 max)(1) H 12m Ø Avg 6.5%

RESTHAVEN/SIMONETTE Falher F Channel Pressure: 5000 psi (34450 kpa) Depth: 2900 m (9514 ft) Gradient: 0.53 psi/ft OGIP: 9 Bcf/Section (20 max)(1)

H 10m Ø Avg 5.0%

16-18 HZTL IP 30 (restricted) 1,300 boepd (7.3 MMcf/d and 113 bbls cond/d)

6 miles

Current Production Model: IP rate - 6 MMCF/D Reserves - 5 BCF, 20-40 Bbl/MM

(1) See Forward-Looking Information and Definitions for definition of ORGIP

7-6 HZTL test rate 13.1 MMcf/d plus liquids @ 2,005 psi FCP

Discovery well at 16-18 had an average first month rate of 1,300 boepd

Stepout well at 7-6 tested at 13.1 mmcfd

Cequence has mapped 28 potential locations on 14 net existing sections

Falher F Pool similar reservoir distribution and quality to nearby Musreau/Kakwa Falher C Pools

Analog pool produces 60 mmcfd from 21 existing producers

Internal model 6 mmcfd IP and 5 bcf recoverable per well

Simonette Wilrich

17

RESTHAVEN WILRICH POOL

WILRICH POOL

6 miles

Deeper Montney exploitation drilling confirms Wilrich pay extension to south

Simonette Wilrich Play

20 net sections currently mapped with 2 wells per section spacing

Deeper Montney drilling has confirmed an extension of the existing trend to the south

Currently planning one well in 2013

Ansell/Edson Wilrich play

Exciting Wilrich resource play 140km south of Simonette area

Cequence controls 31 sections of 100% land and retains 49% WI in Ansell project after recent farmout to JV partner

Competitor wells tested at more than 20 mmcfd plus liquids in the Ansell/Edson area

Simonette Model Economics

IP Rate (mmcf/d)

Liquids (bbls/mmcf)

ORGIP (BCF)(3)

Dev. Capital Cost/Well

(MM)

ROR

NPV (MM)

Model Payout

(months)

Breakeven Gas Price (/mmbtu)

Net Potential Locations

Dunvegan Gas

4.5 50-75 4.0 $6.5 80%+

>$9.0

<16 <$2.00 8/14(5)

Falher (2) 6.5 20 5.0 $7.0 40% $4.2 24 $2.00 28

Wilrich 4.5 20 4.0 $5.5 40% $3.8 23 $2.00 70(6)

Montney 5.5 30(7) 5.0 $7.5 50%+ $7.1 23 <$2.00 260(4)

Working Development Models @ $3.20/mmbtu (+5% gas escalation) and $90/bbl WTI (flat)(1)

18

(1) Without GORR (2) Falher production performance based on Kakwa analog (3) See Forward-Looking Information and Definitions for definition of ORGIP (4) Assumes 1600m laterals & acquisition of Donnybrook lands (5) 8 locations within gas trend, 14 locations within oil trend (6) Includes Ansell /Edson locations (7) 21 bbls/mm condensate

First Half 2013 Guidance, February 4, 2013

First Half 2013 Guidance

Production (boe/d)(1) 10,000

Capital expenditures $49 MM

Operating costs per boe $6.75

Royalties (% of revenue) 8%

Crude oil – WTI (Cdn$/bbl) $90.00

Natural gas – AECO (Cdn$/GJ) $3.00

Funds flow from operations (2)(4) $26 MM

Annualized funds flow from operations (2)(4) $52 MM

June 30, 2013 net debt and working capital deficiency(3) $71 MM

Basic shares outstanding 200.6 MM

(1) Comprised of 51.8 mmcf/d of natural gas and 1,370 boe/d of oil and liquids (2) Funds flow from operations is calculated as cash flow from operating activities before adjustments for decommissioning liabilities (3) Net debt and working capital (deficiency) is calculated as cash and net working capital less commodity contract assets and liabilities (4) First half funds flow sensitivity: +/- $1 AECO is $6 million.

19

Simonette/Resthaven Horizontal Wells

Multiple zones with significant horizontal drilling success

Major companies active in Simonette/Resthaven

Exxon Encana Conoco

CQE land is well-

positioned

Stacked potential of up to 100 bcf per section of total resource (1) on Cequence lands

20

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

6 miles

Conclusions

21

Simonette Montney results confirm the quality and extent of our resource base

Exploration success adds more scope in other formations

Infrastructure in place – excellent operating cost structure

Cequence surrounded by super-majors (validates the potential of the area) Strong balance sheet

Emerging new core area at Edson/Ansell

Highly experienced Board of Directors and Deep Basin Management team with significant

ownership

22

Appendix

Financial Highlights

Q4 2012 Q3 2012 % Change

Average Daily Production (BOE/D) 8,951 8,895 1

Funds flow from operations ($M) (1) $11,603 $10,803 7

Per share, basic and diluted $0.06 $0.06 -

Operating costs per BOE $6.55 $6.88 (5)

G&A per BOE $1.85 $2.19 (16)

Capital expenditures, net ($M) $23,641 $16,838 46

Net debt and working capital (deficiency) ($M)(2) ($45,869) ($48,291) (5)

Weighted average shares outstanding (basic and diluted) (M)

194,224 191,612 1

23

(1) 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

(2) Net debt and working capital (deficiency) is calculated as cash and net working capital less commodity contract assets and liabilities and demand credit facilities and excluding other liabilities

Hedging Approximately 42% of 2013 production hedged at an average $3.61 per mcf

Contract Type Volume GJ/d CAD Price Basis

January 1, 2013 to December 31, 2013 Gas Swap 2,000 $2.84 AECO

January 1, 2013 to December 31, 2013 Gas Swap 2,500 $3.09 AECO

January 1, 2013 to December 31, 2013 Gas Swap 2,500 $3.00 AECO

January 1, 2013 to December 31, 2013 Gas Swap 5,000 $3.10 AECO

January 1, 2013 to December 31, 2013 Gas Swap 2,500 $3.24 AECO

January 1, 2013 to December 31, 2013 Sold Oil Call 200 bbls/d $100.00 usd WTI

January 1, 2013 to December 31, 2013 Gas Swap 2,500 $3.40 AECO

March 1, 2013 to December 31, 2013 Gas Swap 2,500 $3.02 AECO

March 1, 2013 to December 31, 2013 Gas Swap 2,500 $3.17 AECO

January 1, 2014 to September 30, 2014 Gas Swap 2,500 $3.51 AECO

January 1, 2014 to December 31, 2014 Gas Swap 2,500 $3.42 AECO

January 1, 2014 to December 31, 2014 Gas Swap 2,500 $3.53 AECO

Remainder 2013 22,000 GJ/d $3.11/GJ or $3.61/mcf

2014 6,875 GJ/d $3.49/GJ or $4.04/mcf

24

Net Asset Value (NAV)

December 31, 2012 GLJ Report

$M

Proved + Probable, NPV 10% - December 31, 2012 798,200

Land (1) 101,000

Dec 31, 2012 (45,900)

NAV 853,300

Shares Outstanding (M) 200,600

NAV/Share ($/share) 4.25

25

(1) Internal estimate

Simonette Deep Basin Stack

26

Dunvegan

Falher Bluesky / Gething

Montney Wilrich

3075

3050

3025

3000

2950

2975

Upper

Middle

Lower

CURRENT HORIZONAL

TARGET ZONE

Contacts: Paul Wanklyn President & CEO pwanklyn@cequence-energy.com

David Gillis

Vice President, Finance & CFO dgillis@cequence-energy.com

www.cequence-energy.com

3100, 525 - 8th Avenue SW Calgary AB T2P 1G1

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