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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
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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
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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
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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
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