cequence energy ltd February 2016 TSX: CQE
Forward-Looking Information and Definitions Summary of Forward-Looking Statements or Information 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. For a complete description of the forward-looking statements or information and the definitions used in this presentation, see slide 23 "Forward-Looking Statements or Information and Definitions." 2
2015 Corporate Highlights 16-33 Montney well producing initially at 1,800 boepd (30% condensate) Dunvegan oil well at 7-11 in Simonette. IP150-313 bopd 4-11 stepout well drilled and frac cleanup began Jan 31st Two additional wells planned for Q1 2016 deferred to preserve balance sheet 13-11-62-27W5 Refrigeration plant completed 14% under budget. NGTL tie-in project under construction 2015 average production 9,500 boed with current productive capacity of 13,000 boepd Expect NGTL pipeline restrictions reduced in 2016 2016 production expected to range from 9,200 to 9,500 boepd with no additional drilling Maintaining balance sheet strength is critical. Capital spending expected at $8.5 million through first half of 2016: Completion of refrigeration facility and NGTL tie-in Tie-in two wells drilled in Q4 Initiated a strategic alternatives process to maximize shareholder value 3
Corporate Profile Trading Symbol TSX: CQE 2015 Average production 9,500 boepd 52-week trading range $0.24 - $1.11 Shares outstanding 211 MM Insider ownership 11% FD Market capitalization (1) $75 MM Net Debt - Sept 30, 2015 (2) $52.5 MM Debt capacity Long Term Notes Bank line (3) Undrawn $60 MM $60 MM Reserves P + P, December 31, 2014 118 MMBoe F, D & A (4) $10.26 per Boe (1) Based on Cequence stock price of $0.35 (2) Net debt is calculated as net working capital less commodity contract asset and liabilities and demand credit facilities, principal value of senior notes and excluding other liabilities. (3) Voluntarily lowered to reduce standby fees (4) 2014 finding, development and acquisitions costs including future development costs calculated using proved plus probable reserves. 4
Reserves and Finding Costs solid growth per share in reserves $16.00 $14.00 FD&A ($/Boe) 3 year average $10.77 per Boe 140 120 Reserves Reserves increased 140% since 2010 113 118 0.7 0.6 1200 1000 2P Reserve Value $1,004 6 $12.00 $10.00 $8.00 $6.00 $4.00 MMBoe 100 80 60 40 49 67 91 0.5 0.4 0.3 0.2 Boe/share $MM 800 600 400 $715 $525 $797 $854 5 $/share 4 $2.00 20 0.1 200 $0.00 2010 2011 2012 2013 2014 Proved + Probable (Incl FDC) 0 2010 2011 2012 2013 2014 Proved + Probable (2) Total Proved 2P per share 0.0 0 3 2010 2011 2012 2013 2014 Reserve Value 2P per share GLJ Proved + Probable NPV 10% 5
Corporate Guidance November 2015 2015 Guidance Average Production (Boe/d) (1) 9,500 Capital expenditures, net of dispositions $22 MM Operating and transportation costs per Boe $11.20 G&A costs per Boe $2.35 Royalties (% of revenue) 6-8% Crude oil WTI (US$/Bbl) $51.00 Natural gas AECO (Cdn$/GJ) $2.60 Funds flow from operations (2) Net debt and working capital deficiency (3) Basic shares outstanding $26 MM $68 MM 211 MM (1) Comprised of 84% natural gas and 16% 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, demand credit facilities and the aggregate principal amount of the Notes and excluding other liabilities. 6
Simonette Cequence s Key Asset Deep Basin - Approximately 120 km SE of Grande Prairie Multi zone targets including Montney, Gething, Wilrich, Falher and Dunvegan Simonette is 85% of corporate production, and 95%+ of capital 2015 capital guidance of $67 MM (net capital $22 MM) with H2 activity including drilling 3 gross (2 were drilled) Dunvegan oil and 1 gross Montney wells plus participate in 50% Shallow Cut Refrigeration plant expansion at Simonette. CANADA USA SIMONETTE PROJECT Significant upside with > 3.8 TCF gross (1) of total Upper Montney resource in place within the Simonette project area Proved plus probable reserves of 110 MMBOE with NPV of $806 million (B-Tax, 10%) (2) Large land position consisting of 86 net sections of Montney rights and 150 sections of Cretaceous rights Deep Basin 7 (1) See Forward-Looking Information and Definitions for definition of DPIIP and total resource, Upper Montney only. (2) Reserves evaluation by GLJ Petroleum Consultants Ltd. effective December 31, 2014.
8 Simonette Facility Joint Venture» 13-11 Refrigeration Facility
Simonette Egress Strategic location near major infrastructure Optionality on both major gas systems in Alberta Cequence Alliance Meter Station Capacity 120 MMcf/d SIMONETTE Pembina Lator Truck Terminal CQE 9-10 Field Compressor 6 miles Alliance/Aux Sable Deep Cut Plant Chicago, Illinois Proposed Pembina Simonette Truck Terminal NGTL meter station- March 2016-200 MMcf/d 13-11 Facility Curr. capacity -Compression 100 MMcf/d -Refrigeration 120 MMcf/d -Cond stabilization 4,500 bpd 120 MMcfd refrigeration plant (50% WI) on-stream Jan 2016. 14 % under budget. NGTL tie-in underway Expanded Alliance contracts through March 2016 to 55,000 GJ/d fixed differential term sales Improved flow assurance with connection to both TransCanada and Alliance pipeline systems effective April 1, 2016 9
Alberta Deep Basin Montney- An active area NUVISTA Cequence Simonette lands on overpressured Montney trend Industry focusing on High quality low cost liquid rich areas Less exploration/delineation 7 GEN S PARAMOUNT MOSAIC XTO CEQUENCE DELPHI Industry optimization trend continues Longer laterals Decreasing distance between frac stages Sand volumes testing upward of 3 tonne/meter of lateral Deployment system evolution: Coil shift sleeves, plug & perf with tighter clusters, high tolerance ball & seats, combinations 10
Simonette Montney 16-33 strong initial results with high condensate yield and early production performance 16-33 well-deployed new completion technique with 3,050 m lateral and 70 frac stages CQE 16-33 7.5 mmcfd 75 bbl/mm cond 140 meters CURRENT HORIZONTAL TARGET ZONE Results highlight excellent potential of western Simonette lands Upgraded average CQE inventory to 2,500 m laterals (25% longer) with 2.2 times frac stages from historical average Costs decreasing due to changes in wellbore design & lower service costs 6 miles Cequence Land POTENTIAL HORIZONTAL TARGET ZONE New XTO activity and licenses adjacent to CQE will de-risk southwest lands Montney Rights CQE Montney Gas Well CQE Montney Oil Well Recent competitor activity targeting lower Montney in Alberta Deep Basin Industry Montney HZ Well XTO Montney HZ Activity 11
Montney Drilling & Completion Costs Driving Improved Performance Implemented Montney drilling design changes saving time and providing flexibility Set deeper conductor pipe Simplified build angles to intermediate casing point Shallower intermediate casing depth Cemented production casing with coil shift sleeves (less hole conditioning) Costs $ MM/Well 16 14 12 10 8 6 4 2 3.8 5.6 15-28 stages 0.5 t/m 3.4 26 stage 1.0 t/m 4.7 4.0 4.7 4.7 4.7 2.4 4.5 3.5 3.5 4.1 3.9 3200 2400 1600 800 Lateral Length (m) Increased completion effectiveness Longer laterals with 2.2 x tighter frac spacing than historic Minimum 1 tonne/m proppant Full diameter production casing post completion Significant completion & production flexibility without milling operations 16-33 delivered over 30% lower completed cost per meter compared to 2014 program. 12 0 2012 (4 wells) 2013 (10 wells) 2014 (10 wells) Completion Drilling HZ Length (m) 2014 (without plug & perf) (7 wells) 2015 Current estimate using previous well design (2,075m) Current Well 16-33 Well Design Design 70 stage (3,050m) Future planned 2,500m Average Well 63 stage x 40 t 0 Note: Non-pilot wells included only Equipment and tie-in cost $0.3 MM/well Demob cost not included for one off wells
Cequence Montney Gas Well Performance Producing Day Gas Rate (Mcf/d) Wellhead Condensate Yield (Bbls/MMcf) 13 10,000 9,000 8,000 7,000 6,000 5,000 4,000 3,000 2,000 1,000 0 120 100 80 60 40 20 - Historic 5 bcf Montney Model Montney Model Scaled for Increased Length (2500m) Montney Model Scaled for Increased Length/Loading/Spacing Simonette 2014 Average 0 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 Months on Production Average Wellhead Condensate Yield Steady field condensate: 20-40 bbl/mmcf 2014/2015 Average yield All Montney wells: 26 bbl/mmcf 1 3 5 7 9 11 13 15 17 19 21 23 25 27 29 31 33 35 37 39 41 43 Months on Production Previous 2014-15 winter program (10 gross/9 net wells) Consistent repeatable results Higher sand loading than historical wells, production trending above previous average Improved well design (longer and more frac stages) and capital efficiency leads to stronger economics than historical well design (16-33 well is first Montney test case for new design) $50 WTI, $3.00/GJ AECO Historic Montney New Costs (1) New Mean Well Scaled For Length (2) NEW Mean Well Scaled for Length and frac intensity (2) Parameters Length (m) 2,075 2,500 2,500 Frac Stages 24 29 63 Costs (Drill, Complete, Equip) Total ($MM) $6.20 $6.80 $7.70 Drilling Results IP30 Production Rate (MMcf/d) 5.0 6.0 7.8 Reserves (MBOE) 930 1,120 1,456 ORGIP (Bcf) 5.0 6.0 7.8 Economic Indicators F&D ($/BOE) $6.67 $6.07 $5.29 ROR (%) 28% 37% 51% Payout (Years) 2.8 2.3 1.8 NPV10% ($M) $2.4 $3.7 $5.9 Breakeven Gas Price ($/Mcf) (at $50.00 WTI/Bbl) $2.42 $2.15 $1.85 Production Efficiency ($/boed-365) $11,300 $10,300 $9,100 1. Assumes 30 Bbls/MMcf of NGL s and condensate 2. Assumes 35 Bbls/MMcf of NGL s and condensate Includes 5% GORR, Opex $4.00 per Boe incremental, $0.25/mcf midstream capital Includes wells with mechanical failures
Simonette/Karr Dunvegan Emerging Light Oil Development KARR ANALOG Dunvegan Oil play at Simonette is analogous to the Karr Oil Pool Karr Type Log 6-6 Net Pay 9m 15% Ø SIMONETTE Simonette Type Log CQE 10-9 Net Pay 10m 15% Ø Dunvegan Gas Pool Dunvegan Oil Pool 9 gross (7.5 net) sections identified with oil development potential in Dunvegan sand Existing vertical well control and 3D seismic used for resource identification 60 mmbbls OOIP net to Cequence Current development plan shows 28 gross (24 net) locations with average 1,900 meter lateral length. Previously unbooked resource Solution gas gathered to Cequence/KANATA 13-11 Gas Plant Existing Montney padsites well situated for Dunvegan development Dunvegan Gas Pool 14
Simonette Dunvegan Oil CQE 7-11 well flowed 47,000 bbls in 150 operating days (IP150 313 bbls/d) 41 API CQE 4-11 well drilled and completed. Frac cleanup began Jan 31 st Multi-well facility upgrade completed in October: 2,000 bbl oil per day capacity with tank vapor recovery system. Defer two additional locations until summer due to low commodity prices 5-14 Location Type Well Economics - $50 WTI & $3.00/MMBTU Gas 2,000m well Drill, Complete, Equip, Tie-in ($MM) $4.5 MM Production, IP 30 (bbl/d) 300 Production, IP 365 (bbl/d) 240 EUR (Mboe/MSTB) 549/315 NPV BT 10 ($MM) 3.7 Rate of Return (%) 74 Payout (years) 1.3 Reserve Cost ($/boe) $8.21 Break Even Price ($WTI) $29.00 Production efficiency ($/boed - 365) 10,800 15 15-4 Location Type Log GAS GATHERING CQE HZ 7-11 CQE HZ 4-11 (Early rate 148 bopd on cleanup)
Hedging -approximately 50% of 2016 gas production hedged at $3.20 per mcf Contract Type Volume GJ/d CAD Price GAS 2016 January 1, 2016 to March 31, 2016 Average Gas Swap 25,000 $2.88/GJ AECO 2016 April 1, 2016 to September 30, 2016 Average Gas Swap 20,000 $2.64/GJ AECO 2016 October 1, 2016 December 1, 2016 Average Gas Swap 16,700 $2.68/GJ AECO OIL Volume bbl/d CAD Price 2016 January 1, 2016 December 31, 2016 Swap 400 $65.35/bbl 16
Conclusions Longer Montney wells with higher frac intensity enhance the commerciality of future development. Western lands have significantly higher condensate yield. Emerging Dunvegan oil results are very strong Preserve our strong balance sheet with reduced capex program Solid hedge position maintained through 2016 17
Appendix 18 Cequence Simonette 13-11 Compressor Station
Management and Board Management Team Board of Directors Paul Wanklyn - President and CEO Don Archibald - Chairman Todd Brown VP & COO Peter Bannister Steve Stretch - VP Exploration and Chief Geophysicist Rob Cook Dave Gillis - VP Finance and CFO Howard Crone Dave Robinson - VP Exploration and Chief Geologist Brian Felesky James Jackson - VP Engineering Daryl Gilbert Chris Soby - VP Land and Corporate Development Frank Mele Mike Stewart - VP Operations Paul Wanklyn Erin Thorson - Controller James Gray - Director Emeritus 19
Simonette Deep Basin Stack Dunvegan Wilrich Montney Simonette Upper Falher Bluesky / Gething CURRENT HORIZONTAL TARGET ZONE Simonette Lower POTENTIAL HORIZONTAL TARGET ZONE 20
Multiple Zones with Significant Resource Potential at Simonette 2,400m 2,500m 2,700m Zone Dunvegan Gas Dunvegan Oil Falher Wilrich Total Resource Potential/Sec (1) 5-25 BCF 5-10 MMBBL 5-24 BCF 5-24 BCF 2,800m Gething 5-25 BCF 2,950m 3,100m Upper Montney 30-60 BCF 21 (1) See Forward-Looking Information and Definitions for definition of total resource
Simonette Falher and Wilrich plays Falher play Cequence has 28 potential locations on 14 net existing sections Wilrich play 20 net sections currently mapped with 40 potential locations 6 miles 22
Forward-Looking Statements or Information and Definitions Certain statements included in this presentation constitute forward-looking statements or forward-looking information under applicable securities legislation. Such forward-looking statements or information are provided for the purpose of providing information about management's current expectations and plans relating to the future. Readers are cautioned that reliance on such information may not be appropriate for other purposes, such as making investment decisions. Forward-looking statements or information typically contain statements with words such as "anticipate", "believe", "expect", "plan", "intend", "estimate", "propose", "project" or similar words suggesting future outcomes or statements regarding an outlook. Forwardlooking statements or information concerning Cequence in this presentation may include, but are not limited to, statements or information with respect to: guidance, forecasts and related assumptions; expected production growth and cash flow growth and the respective timing thereof; capital spending; expected resource potential and future reserves; hedging objectives; business strategy and objectives; type curves; drilling, development and exploration plans and the timing, associated costs and results thereof; future net debt and funds flow; commodity pricing and expected royalties; costs associated with operating in the oil and natural gas business; and future production levels, including the composition thereof. Forward-looking statements or information are based on a number of factors and assumptions which have been used to develop such statements and information but which may prove to be incorrect. The Company believes that the expectations reflected in such forward-looking statements or information are reasonable; however, undue reliance should not be placed on forward-looking statements because the Company can give no assurance that such expectations will prove to be correct. In addition to other factors and assumptions which may be identified in this presentation, assumptions have been made regarding, among other things: the impact of increasing competition; the timely receipt of any required regulatory approvals; the ability of the Company to obtain qualified staff, equipment and services in a timely and cost efficient manner; the ability of the operator of the projects which the Company has an interest in to operate the field in a safe, efficient and effective manner; the ability of the Company to obtain financing on acceptable terms; field production rates and decline rates; the ability to replace and expand oil and natural gas reserves through acquisition, development or exploration; the timing and costs of operating the Company s business; the ability of the Company to secure adequate product transportation; future oil and natural gas prices; currency, exchange and interest rates; the regulatory framework regarding royalties, taxes and environmental matters; and the ability of the Company to successfully market its oil and natural gas products. Readers are cautioned that the foregoing list is not exhaustive of all factors and assumptions which have been used. Forward-looking statements or information are based on current expectations, estimates and projections that involve a number of risks and uncertainties which could cause actual results to differ materially from those anticipated by the Company and described in the forward-looking statements or information. These risks and uncertainties may cause actual results to differ materially from the forward-looking statements or information. The material risk factors affecting the Company and its business are contained in the Company's Annual Information Form which is available at SEDAR at www.sedar.com. The forward-looking statements or information contained in this presentation are made as of the date hereof and the Company undertakes no obligation to update publicly or revise any forward-looking statements or information, whether as a result of new information, future events or otherwise unless required by applicable securities laws. The forward-looking statements or information contained in this presentation are expressly qualified by this cautionary statement. Discovered Petroleum in Place ("DPIIP") and "Contingent Resources": 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. 23
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 24