March 2013 TD 2013 Securities Calgary Energy Conference

March 2013 TD 2013 Securities Calgary Energy Conference

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. DISCOVERED PETROLEUM INITIALLY IN PLACE (DPIIP): 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. "Best estimate" is defined in COGEH with respect to entity level estimates, as the value derived by an evaluator using deterministic methods that best represent the expected outcome with no optimism or conservatism. If probabilistic methods are used, there should be at least a 50 percent probability (P50) that the quantities actually recovered will equal or exceed the best estimate. OOIP and OGIP estimates are internally estimated and prepared by a qualified reserves evaluator. 2

Cequence is focused in the Deep Basin of Alberta Control 170,000 net acres in the Deep Basin High quality, operated asset base in multi-zone, liquids-rich gas areas with Montney as primary zone of interest Simonette winter drilling program has expanded the extent and quality of our large resource base in multiple formations Peace River Arch/NE BC - 2012 Production: 1,800 boe/d SIMONETTE CANADA USA Emerging new Wilrich resource play at Edson Deep Basin Deep Basin - 2012 Production: 7,100 boe/d Ansell/Edson Wilrich Project 3

Corporate Profile Trading Symbol TSX: CQE Current Production (boe/d) 11,000 52-week trading range $0.88-$2.05 Shares outstanding (3) Insider ownership Market capitalization (1) March 31, 2013 net debt (2) Bank line 211 million 12% FD $360 million $78 million $125 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 share pursuant to the acquisition of Montney Assets expected to close April 15, 2013. 4

2013 Guidance, May, 2013 2013 Full Year Guidance Production (boe/d) (1) 10,000 10,500 Exit Production Guidance (boe/d) 11,500 Capital expenditures $97 MM Operating costs per boe $6.75 Royalties (% of revenue) 9% Crude oil WTI (Cdn$/bbl) $95.00 Natural gas AECO (Cdn$/GJ) $3.35 Funds flow from operations (2)(4) $55 MM Dec 31, 2013 net debt and working capital deficiency (3) $88 MM Basic shares outstanding 210.9 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) Full year sensitivity 5

Recent Highlights Simonette winter drilling success results in record current production levels of 11,000 boepd 2013 Proven plus probable reserves increased to 113 mmboe with an NPV 10 value of $1 billion Low cost structure - Q1 total cash costs $11.33 per boe Strong balance sheet - 2013 exit debt is 1.3 times Q4 run rate cash flow 6

MMBoe Boe/share $MM $/share Reserves and Finding Costs $16.00 FD&A ($/boe) 140 Reserves 0.70 1200 2P Reserve Value $6 $14.00 120 113 0.60 1000 $1052 $12.00 $10.00 $8.00 $6.00 $4.00 $2.00 100 80 60 40 20 49 67 91 0.50 0.40 0.30 0.20 0.10 800 600 400 200 $525 $715 $797 $5 $4 $0.00 2010 2011 2012 Proved + Probable (Incl FDC) 0 2010 2011 2012 Q1 2013 Proved + Probable Total Proved 2P per share 0.00 0 $3 2010 2011 2012 Q1 2013 Reserve Value 2P per share Proved + Probable GLJ Dec 31, 2012 7

boe/d $/boe Corporate Production and Cash Costs 12,000 25 10,000 8,000 20.30 19.37 7,485 8,185 9,125 9,833 8,879 9,464 8,660 8,895 8,951 8,822 20 6,000 17.38 16.76 4,000 2,000 2,444 3,197 4,619 14.99 14.08 14.21 12.84 12.58 13.88 11.87 10.65 11.33 15 0 10 Natural Gas Oil & NGL Cash Costs* *Operating cost, transportation, G&A and Interest 8

Simonette Infrastructure 3D Seismic Coverage Control 220 gross operated sections (avg. 85% W.I) with excellent land tenure Cequence Alliance Meter Station Capacity 120 mmcf/d 9-10 Field Compressor Trilogy Plant CQE W.I. = 25% Capacity 10 mmcf/d 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 13-11 Compressor Station Keyera Processing Facility Capacity 153 mmcf/d To Aux Sable Deep Cut Plant Chicago, Illinois Q1 2013 operating costs were $4.18 per boe resulting in a field netback of $20.27 per boe 13-11 Facility 5,000 HP Compression and dehydration 70% of Cequence current corporate production is at Simonette 6 miles 9

Multiple Zones with Significant Resource Potential 6 miles 2,400m 2,500m 2,700m Zone Dunvegan Falher Wilrich Total Resource Potential/Sec (1) 5-25 BCF 5-24 BCF 5-24 BCF 2,800m Gething 5-25 BCF 2,950m 3,100m Upper Montney 30-60 BCF (1) See Forward-Looking Information and Definitions for definition of total resource 10

Simonette Montney Large Scale Resource Play 6 miles Exxon cased well Montney Gas/Condensate trend Recent wells continue to exceed model well rates Up to 150 meters of siltstone to very fine sandstone reservoir Petrobakken cased well 74 MMBOE Proved plus probable reserves booked with 81 undeveloped locations in Upper Montney only 9-21 test rate - 8.9 mmcfd + 480 bbl/d condensate at 1030 psi FTP Liquids yield (C3+) averages 30 bbls/mmcf (70% condensate) DPIIP independently calculated at 2.5 TCF (1) over 66 sections 3-21 test rate - 12.4 mmcfd + 371 bbl/d condensate at 1530 psi FTP Conoco cased well Oil Prone trend developing in North Simonette Competitor drilling currently derisking Cequence land 20 net sections in potential oil trend (1) See Forward-Looking Information and Definitions for definition of DPIIP and total resource 11

Producing Daily Gas Rate (mcf/d) Montney Gas/Condensate Working Model vs. Simonette gas wells CURRENT MODEL 12000 11000 10000 9000 8000 7000 6000 Newest wells producing above model rates RESERVES PRODUCTION 5.0 BCF raw natural gas 100 MBbl Condensate 50 MBbl Propane/Butane 2-22-61-27 1-31 04-04 01-11-061 09-25 IP 05-35 13-22 10-16 03-21 5.5 mmcfd 110 bpd C5+ 55 bpd C3/C4 1,100 boepd 3-18 Average Well Production CQE Simonette Model YEAR 1 AVERAGE 2.9 mmcfd 63 bpd C5+ 30 bpd C3/C4 550 boepd 5000 4000 3000 2000 1000 0 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 25 Months on Production 12

NPV 10% BT ($ M) Montney Half Cycle Economic Sensitivity to Flat Gas Price and Recoverable Gas in Place per Well 20,000 15,000 Assumptions: Net NGL Yield: 30 Bbl/MMcf C3+ Capital: $7.5 MM Oil Price: $90/bbl WTI 10,000 5,000 0 1.00 2.00 3.00 4.00 5.00 6.00 7.00 Flat AECO Gas Price ($/mmbtu) 3.0 bcf + NGL's 5.0 bcf + NGL's 7.0 bcf + NGL's 13 (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

Drill & Completion Costs $M Meters drilled Montney Drilling and Completion Costs 12000 2010 2011 2012 2013 5800 10000 5550 Target $7.5 MM (D,C,TI) Drilling costs declined 30% in the past year while increasing length drilled 8000 6000 4000 2000 0 5300 5050 4800 4550 4300 Recent wells have longer laterals (2,400 m+) and more fracs Last two wells have achieved long term target - $7.5 MM per well (drill, complete & tie in) Pad development should offer significant future capital cost savings Completion Cost Drill & Case Cost MD * 8-21 costs contain original well combined with re-drill 9-21 completion costs 14

Measured Depth (m) Montney Drilling Time Comparison 0 500 1000 1500 2000 2500 CQE 2012 Avg. 32 days/5447m CQE 2011 Avg. 42 days/4922m Wapiti avg. 49 days/4305m Resthaven avg. 55 days/4922m Cequence winter 2012/13 wells average 500 meters longer and are 25% faster to drill than the previous year Faster penetration equates to lower capital cost 3000 3500 4000 4500 5000 5500 6000 0 5 10 15 20 25 30 35 40 45 50 55 Days from spud 2011 CQE Shortest Drill Time 2012 CQE Shortest Drill Time Wapiti Shortest Drill Time CQE Simonette Avg 2011/12 (7 wells) Wapiti Average (12 wells) Resthaven Shortest Drill Time CQE Simonette Avg 2012/13 (4 wells) Resthaven Average (19 wells) *Information compiled from Canadian Discovery Frac Data Base and public records 15

Simonette Dunvegan Oil, and Gas/Condensate Play Current Production Model: IP rate - 4.5 MMCF/D Reserves 4.0 bcf and 50-150 Bbl/mm NGL 10-2 well tested above the model rate at 16.4 mmcf/d plus liquids at 2,380 psi FCP and average 30 day IP was 12.2 mmcf/d Resthaven gas/condensate pool Oil prone Simonette oil pool 42º API Resthaven pool is highly productive in the Dunvegan formation from 10 existing horizontals 10-2 HZTL 30 day IP rate 12.2 mmcfd + 170 Bbl/d condensate Current rate 16 mmcfd + 170 Bbl/d condensate 6 miles Cequence has mapped 22 potential locations on 11 net existing sections along gas and oil trend Up to 25 BCF/sec resource potential 16

Simonette Falher Trends New Discovery KAKWA Falher C Channel Pressure: 3950 psi Depth: (27216 kpa) 2400 m (7891 ft) Gradient: 0.5-0.55 psi/ft OGIP: 12 Bcf/Section (20 max) (1) H 12m Ø Avg 6.5% Current Production Model: IP rate - 6 MMCF/D Reserves - 5 BCF, 20-40 Bbl/MM Discovery well at 16-18 had an average first month rate of 1,300 boepd and average 30 day IP rate was 7.3 mmcfd Stepout well at 7-6 tested at 13.1 mmcfd 16-18 HZTL IP 30 (restricted) 1,300 boepd (7.3 mmcf/d and 113 bbls cond/d) 7-6 HZTL 30 day IP rate 7.5 mmcfd + 202 Bbl/d condensate 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% 6 miles 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 17 (1) See Forward-Looking Information and Definitions for definition of ORGIP

Simonette Wilrich 6 miles Simonette Wilrich Play WILRICH POOL 20 net sections currently mapped with 40 potential locations Deeper Montney drilling has confirmed an extension of the existing trend to the south Currently planning one well in winter 2014 Ansell/Edson Wilrich play RESTHAVEN WILRICH POOL Deeper Montney exploitation drilling confirms Wilrich pay extension to south Emerging 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 18

Simonette Model Economics Working Development Models @ $3.20/mmbtu (+5% gas escalation) and $90/bbl WTI (flat) (1) 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) (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 19

Simonette/Resthaven Horizontal Wells Multiple zones with significant horizontal drilling success Major companies active in Simonette/Resthaven Exxon Encana Conoco CQE land is wellpositioned Stacked potential of up to 100 bcf per section of total resource (1) on Cequence lands 6 miles 20 (1) See Forward-Looking Information and Definitions for definition of total resource

Conclusions 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 21

22 Appendix

Financial Highlights Q1 2013 Q4 2012 % Change Average Daily Production (BOE/D) 8,822 8,951 (1) Funds flow from operations ($M) (1) $10,652 $11,603 (8) Per share, basic and diluted $0.05 $0.06 (17) Operating costs per BOE $7.24 $6.55 11 G&A per BOE $2.02 $1.85 9 Capital expenditures, net ($M) $43,677 $23,641 85 Net debt and working capital (deficiency) ($M) (2) ($78,365) ($45,869) 71 Weighted average shares outstanding (basic and diluted) (M) 210,610 194,224 8 (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 23

Hedging Approximately 45% of 2013 production hedged at an average $3.65 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 January 1, 2014 to December 31, 2014 Gas Swap 2,500 $3.70 AECO January 1, 2013 to December 31, 2013 Sold Oil Call 200 bbls/d $110.00 usd WTI Remainder 2013 24,500 GJ/d $3.15/GJ or $3.65/mcf 2014 10,000 GJ/d $3.54/GJ or $4.11/mcf 24

Net Asset Value (NAV) December 31, 2012 GLJ Report $M $M April 30, 2013 GLJ Report Proved + Probable, NPV 10% 798,200 1,052,742 Land (1) 101,000 101,000 Net Debt (45,900) (78,365) (2) NAV 853,300 1,075,377 Shares Outstanding (M) 200,600 210,900 NAV/Share ($/share) 4.25 5.10 (1) Internal estimate (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. 25

Simonette Deep Basin Stack Dunvegan Wilrich Montney 2950 Upper 2975 CURRENT HORIZONAL TARGET ZONE Falher Bluesky / Gething 3000 Middle 3025 Lower 3050 3075 26

www.cequence-energy.com 3100, 525-8th Avenue SW Calgary AB T2P 1G1 Phone: 403-229-3050 Fax: 403-229-0603 Contacts: Paul Wanklyn President & CEO pwanklyn@cequence-energy.com David Gillis Vice President, Finance & CFO dgillis@cequence-energy.com