Peters & Co. Low Cost and Large Scale Resource Conference Winnipeg, Montreal, Toronto - March 2013

Transcription

1 Peters & Co. Low Cost and Large Scale Resource Conference Winnipeg, Montreal, Toronto - March 2013 March 2013

2 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

3 Cequence is focused in the Deep Basin of Alberta 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 Peace River Arch/NE BC Production: 1,800 boe/d SIMONETTE CANADA USA Control 170,000 net acres within the Deep Basin Deep Basin Deep Basin Production: 7,100 boe/d Ansell/Edson Wilrich Project 3

4 Corporate Profile Trading Symbol Current production TSX: CQE 9,000 boepd 2013 First Half Production Guidance 10,000 boepd 52-week trading range $0.88-$2.05 Shares outstanding Insider ownership Market capitalization (1) December 31, 2012 net debt (2) Bank line 201 million 12.6% FD $340 million $46 million $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) Funds flow from operations is a non-gaap term that represents cash flow from operating activities before adjustments for decommissioning liability expenditures, proceeds from the sale of commodity contracts and net changes in non-cash working capital. 4

5 Recent Highlights Simonette winter drilling success will generate a step-change in production in the second quarter of 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 5

6 2012 Reserves and Finding Costs $16.00 $14.00 $12.00 $10.00 $8.00 $6.00 $4.00 $2.00 $0.00 FD&A ($/boe) Proved + Probable (Incl FDC) Reserves (MMBoe) Proved + Probable Total Proved Reserve Value ($MM) $797 $715 $ Proved + Probable GLJ Dec 31, 2012 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 6

7 boe/d $/boe Corporate Production and Cash Costs 12, ,000 8, ,485 8,185 9,125 9,833 8,879 9,464 8,660 8,895 8, , ,000 2,000 2,444 3,197 4, Natural Gas Oil & NGL Cash Costs* *Operating cost, transportation, G&A and Interest 7

8 Simonette Infrastructure 6 miles 3D Seismic Coverage Control 220 gross operated sections (avg. 75% 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 Compressor Station Keyera Processing Facility Capacity 153 mmcf/d To Aux Sable Deep Cut Plant Chicago, Illinois Q operating costs are $3.81 per boe resulting in a field netback of $20.60 PHASE 4 FACILITY EXPANSION COMPRESSION AND CONDENSATE STABILIZATION Phase 4 facility expansion expected startup April

9 Multiple Zones with Significant Resource Potential 6 miles 2,400m Zone Dunvegan Total Resource Potential/Sec (1) 5-25 BCF 2,500m 2,700m Falher Wilrich 5-24 BCF 5-24 BCF 2,800m Gething 5-25 BCF 2,950m 3,100m Upper Montney BCF (1) See Forward-Looking Information and Definitions for definition of total resource 9

10 Simonette Montney Large Scale Resource Play 6 miles Exxon cased well Exxon cased well 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 Petrobakken cased well 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 Testing Liquids yield (C3+) averages 30 bbls/mmcf (70% condensate) 3-18 test rate 12.9 mmcfd+ 1,775 psi FCP Donnybrook Lands Conoco cased well Oil Prone trend developing in North Simonette Competitor drilling currently de-risking Cequence land 20 net sections in potential oil trend (1) See Forward-Looking Information and Definitions for definition of OOIP and total resource 10

11 Producing Daily Gas Rate (mcf/d) Montney Gas/Condensate Working Model vs. Simonette gas wells RESERVES PRODUCTION CURRENT MODEL 5.0 BCF raw natural gas 100 MBbl Condensate MBbl Propane/Butane IP YEAR 1 AVERAGE mmcfd 2.9 mmcfd bpd C5+ 63 bpd C bpd C3/C4 30 bpd C3/C , boepd 550 boepd Average Well Production CQE Simonette Model Months on Production 11

12 NPV 10% BT ($ M) Montney Half Cycle Economic Sensitivity to Flat Gas Price and Recoverable Gas in Place per Well 20,000 Net NGL Yield: 30 Bbl/MMcf C3+ Capital: $7.5 MM Oil Price: $90/bbl WTI 15,000 10,000 5, Flat AECO Gas Price ($/mmbtu) 3.0 bcf + NGL's 5.0 bcf + NGL's 7.0 bcf + NGL's 12 (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

13 Drill & Completion Costs $M Meters drilled Montney Drilling and Completion Costs Target $7.5 MM (D,C,TI) Most recent wells have longer laterals (2,400 m+) and more frac stages 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 Completion Cost Drill & Case Cost MD * 8-21 costs contain original well combined with re-drill 9-21 completion costs 13

14 Measured Depth (m) Montney Drilling Time Comparison The Simonette area offers efficient penetration rates compared to other Deep Basin Montney areas 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 previous year Faster penetration equates to lower capital cost Winter 2012/13 - Longer wells/ fewer drilling days Days from spud 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) *Information compiled from Canadian Discovery Frac Data Base and public records 14

15 Simonette Dunvegan Oil, and Gas/Condensate Play Current Production Model: IP rate MMCF/D Reserves 4.0 bcf and Bbl/mm NGL 16-2 well tested above the model rate at 16.4 mmcf/d plus liquids at 2,380 psi FCP Resthaven gas/condensate pool Oil prone Simonette oil pool 42º API 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 16-2 HZTL test rate 16.4 mmcf/d plus 2,380 psi FCP Up to 25 BCF/sec resource potential 6 miles 15

16 Simonette Falher Trends New Discovery KAKWA Falher C Channel Pressure: 3950 psi Depth: (27216 kpa) 2400 m (7891 ft) Gradient: 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, Bbl/MM Discovery well at 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 HZTL IP 30 (restricted) 1,300 boepd (7.3 MMcf/d and 113 bbls cond/d) 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% 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 7-6 HZTL test rate 13.1 MMcf/d plus 2,005 psi FCP 6 miles 16 (1) See Forward-Looking Information and Definitions for definition of ORGIP

17 Simonette Wilrich 6 miles Simonette Wilrich Play WILRICH POOL 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 RESTHAVEN WILRICH POOL Deeper Montney exploitation drilling confirms Wilrich pay extension to south 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 17

18 Simonette Model Economics Working Development $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 $6.5 80%+ >$9.0 <16 <$2.00 8/14 (5) Falher (2) $7.0 40% $ $ Wilrich $5.5 40% $ $ (6) Montney (7) 5.0 $7.5 50%+ $ <$ (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 18

19 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) Annualized funds flow from operations (2)(4) June 30, 2013 net debt and working capital deficiency (3) Basic shares outstanding $26 MM $52 MM $71 MM 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

20 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

21 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 22 Appendix

23 Financial Highlights Q Q % 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 $ Operating costs per BOE $6.55 $6.88 (5) G&A per BOE $1.85 $2.19 (16) Capital expenditures, net ($M) $23,641 $16, Net debt and working capital (deficiency) ($M) (2) ($45,869) ($48,291) (5) Weighted average shares outstanding (basic and diluted) (M) 194, ,612 1 (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

24 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 $ 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 ,000 GJ/d $3.11/GJ or $3.61/mcf ,875 GJ/d $3.49/GJ or $4.04/mcf 24

25 Net Asset Value (NAV) December 31, 2012 GLJ Report $M Proved + Probable, NPV 10% - December 31, ,200 Land (1) 101,000 Dec 31, 2012 (45,900) NAV 853,300 Shares Outstanding (M) 200,600 NAV/Share ($/share) 4.25 (1) Internal estimate 25

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

27 3100, 525-8th Avenue SW Calgary AB T2P 1G1 Phone: Fax: Contacts: Paul Wanklyn President & CEO David Gillis Vice President, Finance & CFO