Forward-Looking Information and Definitions

Transcription

1 2013 National Bank Financial Markets Energy Conference Intermediate Energy Growth & Yield Conference Toronto, Ontario February 13 th & 14 th, 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 Built a high quality, operated asset base in multi-zone, liquids-rich gas areas Simonette winter drilling program will expand the extent and quality of our large resource base in multiple formations New JV at Ansell will test an emerging high rate horizontal Wilrich resource play Peace River Arch/NE BC Production Est: 1,800 boe/d SIMONETTE CANADA USA Control 170,000 net acres in the Deep Basin Deep Basin Deep Basin Production Est: 7,100 boe/d Ansell/Edson Wilrich Project 3

4 Corporate Profile Trading Symbol Current production TSX: CQE 9,000 boepd 52-week trading range $0.88-$2.17 Shares outstanding Insider ownership Market capitalization (1) Forecast December 31, 2012 net debt (2) Bank line 200 million 12% FD $300 million $48 million $100 million 2012 Average Production Guidance 8,900 boepd 2012 Budgeted Net Capital Expenditures $80 million 2012 Budgeted Funds Flow (3) $33 million (1) Based on Cequence stock price of $1.50 (2) Net debt is calculated as net working capital less commodity contract asset and liabilities and demand credit facilities and excluding other liabilities, and including expected net proceeds of $15 million from the November 2012 flow through financing. (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 Montney Wells continue to perform Most recent well tested at 12.9 mmcfd + liquids at 1,775 psi FCP Exploration Drilling showing excellent potential Falher horizontal stepout well currently drilling Dunvegan horizontal well tested at 16.4 mmcf/d at 2380 psi FCP Wilrich JV at Ansell/Edson Initial horizontal test well currently drilling Strong Balance Sheet Expect Q2 net debt of $71 million (1.4 times annualized 6 month fundsflow) Strong hedge position - 42% of current volume at $3.60 per mcf 5

6 $/boe Cash Costs per Boe Q *Cash costs consist of operating expense, transportation costs, general and administrative expense and interest expense 6

7 First Half 2013 Guidance 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 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. 7

8 Simonette Infrastructure 6 miles 3D Seismic Coverage Control 220 gross operated sections (avg. 75% W.I) with excellent land tenure 7 KM LOOPING Cequence Alliance Meter Station Capacity 120 mmcf/d Compressor Station 9-10 Field Compressor Trilogy Plant CQE W.I. = 25% Capacity 10 mmcf/d Keyera Processing Facility Capacity 153 mmcf/d To Aux Sable Deep Cut Plant Chicago, Illinois 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 Aux Sable agreement provides access to deep cut processing and avoids the potential $30- $35 million of capital for the initial 40 mmcfd gas plant while enhancing operating netbacks Phase 4 facility expansion expected completion - Q PHASE 4 FACILITY EXPANSION COMPRESSION AND CONDENSATE STABILIZATION NEW FACILITY CAPABILITY 75 MMCFD CAPITAL COST $5.5 MM (INCL PIPELINES) Q Capital cost $5.5 million Capacity increased to 75 mmcfd 8

9 Stacked Zones Contain Significant Resources 6 miles 2,400m 2,500m 2,700m Zone Dunvegan Falher Wilrich Total Resource Potential/Sec (1) 5-10 BCF 5-24 BCF each 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 Liquids-Rich Resource Play Petrobakken drilling Imperial cased well Conoco drilling Imperial drilling 8-21 Redrilling lateral Gas/Condensate trend- CQE wells outperforming expectations Significant industry activity offsetting Cequence 50 net sections mapped on existing trend at an average 40 bcf of total resource per section (1) Approximately 200 potential horizontal locations assuming 4 wells per section Liquids yield (C3+) ranges from bbls/mmcf (70% condensate) Average net 30 bbls/mm C3+ Three firm wells planned in winter program. Oil Prone trend developing in North Simonette Three HZ CQE wells completed with average stabilized rates of 135 boepd (52% oil/condensate) after 3 months Competitor drilling currently de-risking Cequence land 20 net sections in potential oil trend with average internally estimated OOIP of 15 mmbbls (1) per section IP rate 2 mmcfd despite mechanical restrictions 10 6 miles 3-18 Test rate 12.9 mmcfd + 1,775 psi FCP Imperial location (1) See Forward-Looking Information and Definitions for definition of OOIP and total resource

11 Producing Daily Gas Rate (mcf/d) Well count Montney Gas/Condensate CQE Working Model vs. 8 CQE gas wells to date test rate RESERVES CURRENT MODEL 5.0 BCF raw natural gas 100 MBbl Condensate 50 MBbl Propane/Butane PRODUCTION IP Average Well Production CQE Simonette Model 5.5 mmcfd 110 bpd C5+ 55 bpd C3/C4 1,100 boepd YEAR 1 AVERAGE 2.9 mmcfd 63 bpd C5+ 30 bpd C3/C4 550 boepd DRILLING PROGRAM Months on Production

12 Drill & Complete Costs $MM boe/d $/m Measured Depth Montney Drilling Costs 7,000 6, Drill & Case Cost* $1,450 $1, drilling costs declining while wellbore length increasing 5,000 4,000 $/m MD $1,150 $1,000 Recent wells are 5,500 meters measured depth with 2,500 meter lateral 3,000 $850 Padsites reduce access and tie-in costs 2,000 1,000 $700 $550 Improving bit design, drilling fluids, and well path planning 0 $ * Includes liner cost ** Longer wells have 2,400+ m laterals

13 Drill & Complete Costs $M Drill & Complete Costs $MM $M per Frac Stage Montney Completion Costs 6,000 5, $318 Completion Cost Foam Frac Mechanical Problems Frac cost per stage $258 $ $350 $300 Cost per frac showing steady improvement Improved fluid handling in the fieldtanks/flow-lines 4,000 $227 $250 Testing in-line 3,000 2,000 1,000 0 $210 $199 $185 $179 $173 $143 $151 $131 $ $200 $150 $100 # of Stages Completed $50 Two wells out of the range due to mechanical issues and high cost fluid Longer laterals with more frac stages should increase rate and recoverable reserves 13

14 NPV 10 ($M) Montney Economic Sensitivity to Gas Price and Net Liquids Yield 25,000 20,000 15,000 IP: 5.5 MMcf/d ORGIP: 5.0 BCF (1) NGL Yield: 20 to 60 Bbl/MMcf C3 + (70% Condensate) Capital: $7.5 MM 10,000 5, AECO Gas price ($/mmbtu) 20 Bbl/MMcf NGL Yield 30 Bbl/MMcf NGL Yield 45 Bbl/MMcf NGL Yield (1) See Forward-Looking Information and Definitions for definition of ORGIP 14 * Oil $90/bbl, C3 $31.5/bbl,C4 $70/bbl, C5+ $95/bbl

15 Simonette Dunvegan Oil, and Gas/Condensate Play 16-2 well tested 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 16-2 Test Rate 16.4 mmcf/d plus 2380 psi FCP 6 miles 15

16 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% HZTL IP 30 (restricted) 1,300 boepd (7.3 MMcf/d and 113 bbls cond/d) 4-6 drilling Production Model: 6 MMCF/D for 5 BCF, BBL/MM 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% Discovery well at had an average first month rate of 1,300 boepd Cequence has mapped 28 potential locations on 14 net existing sections Stepout well at 4-6 located 3 miles south of recent discovery at Currently drilling Falher F Pool similar reservoir distribution and quality to nearby Musreau/Kakwa Falher C Pools but reservoir pressure higher at Resthaven Analog pool produces 60 mmcfd from 21 existing producers Internal model 6 mmcfd IP and 5 bcf recoverable per well 6 miles 16 (1) See Forward-Looking Information and Definitions for definition of ORGIP

17 Simonette Wilrich 6 miles 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 WILRICH POOL RESTHAVEN WILRICH POOL Deeper Montney exploitation drilling confirms Wilrich pay extension to south Ansell/Edson Wilrich play Cequence has 31 sections of 100% land JV signed with initial two wells committed on Cequence controlled land first well currently drilling Additional rolling options (6 wells) to earn entire 31 sections CQE retains 49% WI in Ansell project Offsetting wells tested at more than 20 mmcfd plus liquids 17

18 Simonette Model Economics CQE Working Development $4.00/mmbtu and $90/bbl WTI (1)(3) IP Rate (mmcf/d) Liquids (bbls/mmcf) ORGIP (BCF) (6) Dev. Capital Cost/Well (2) (MM) ROR NPV (MM) Model Payout (months) Breakeven Gas Price (/mmbtu) Net Potential Locations Dunvegan Gas $6.5 80%+ >$9.0 <16 <$ Falher (4) $7.0 60% $ $ Wilrich $5.5 70% $ $ Montney (5) 5.0 $7.5 70% (7) $ <$ (8) 18 (1) Economics calculated post Aux Sable tie-in (2) Drill, complete, tie-in, slick water (3) Without GORR (4) Falher production performance based on Kakwa analog (5) 21 bbls/mm condensate (6) See Forward-Looking Information and Definitions for definition of ORGIP (7) Strip price ROR 50% (8) Assumes 1600m laterals

19 19 Independent Gas Play Ranking 4 CQE plays rank in the top 13 in North America

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 Montney results outperforming type curve Exploration in new uphole zones could add significant value Infrastructure in place - positioned to accelerate drilling activity and production growth Cequence surrounded by super-majors (validates the potential of the area) Strong balance sheet New joint venture at Ansell Highly experienced Deep Basin management team and Board of Directors 21

22 22 Appendix

23 Financial Highlights Q Q % Change Average Daily Production (BOE/D) 8,895 8,660 3 Funds flow from operations ($M) (1) $10,803 $4, Per share, basic and diluted $0.06 $ Operating costs per BOE $6.88 $8.32 (17) G&A per BOE $2.19 $2.56 (14) Capital expenditures, net ($M) $16,838 $6, Net debt and working capital (deficiency) ($M) (2) ($48,291) ($43,855) 10 Weighted average shares outstanding (basic and diluted) (M) 191, , (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 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, , ,000 2,000 2,444 3,197 4, Natural Gas Oil & NGL Opex, Transportation, G&A and Interest 24

25 Hedging Approximately 42% of 2013 production hedged at an average $3.60 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 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 25

26 Reserves Independent Reserves Evaluation (1) Dec 31, Proved Developed Producing (mboe) 14,675 13,018 ($M) (4) 202, ,163 Proved (mboe) 35,077 27,332 ($M) (4) 389, ,465 FD&A ($/BOE) FDC ($MM) RLI (years) 10.7 (2) 10.0 (3) Proved + Probable (mboe) 67,443 48,863 ($M) (4) 715, ,635 FD&A ($/BOE) FDC ($MM) RLI (years) 20.5 (2) 17.9 (3) (1) Independent reserves evaluator is GLJ Petroleum Consultants ( GLJ ) (2) RLI based on 2011 annual production of 9,010 boe/d (3) RLI based on Q4, 2010 production of 7,485 boe/d 26 (4) Discounted at 10%

27 Land & Net Asset Value (NAV) December 31, 2011 GLJ Report Escalated Strip Pricing (1) Proved + Probable, NPV 10% - December 31, 2011 $M $M 715, ,887 Land (2) 50,880 50,880 Dec 31, 2012 Estimated Net Debt (3) (48,000) (48,000) NAV 718, ,767 Shares Outstanding (M) (4) 200, ,600 NAV/Share ($/share) (1) Based on the net present value of the future net revenue from the Company s proved plus probable reserves (discounted at 10%) with benchmark future pricing used in the Company s reserve report at December 31, 2011 adjusted to March 5, 2012 escalated strip prices (2) 254,400 $200/acre (3) Estimated net debt based on Cequence s 2012 guidance is calculated as cash and net working capital less commodity contract asset and demand credit facilities and excluding other liabilities and include proceeds of November 2012 financing. (4) Common voting shares outstanding at September 30, 2012 and including common shares issued in November 2012 financing 27

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

29 3100, 525-8th Avenue SW Calgary AB T2P 1G1 Phone: Fax: Contacts: Paul Wanklyn President & CEO David Gillis Vice President, Finance & CFO