July cequence. energy ltd
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1 July 2014 cequence energy ltd
2 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 30 "Forward Looking Statements or Information and Definitions." 2
3 Montney Focused Deep Basin Gas PEACE RIVER CANADA USA Large operated land position in core Montney trend in Alberta Strong balance sheet, exit 2014 debt 0.6 times cashflow Facilities in place Current production 10,400 Boepd Plan to reach 15,000 Boepd in next 9 months Deep Basin SIMONETTE PROJECT GRANDE PRAIRIE SIMONETTE PROJECT British Columbia Alberta 3
4 Alberta Deep Basin Montney R9 R8 R7 R6 R5 R4 R3 R2 R1W6 R26 R25 R24 R23 R22 R21W5 T69 T68 T67 WAPITI KARR ANTE CREEK Cequence owns 89 net sections of Montney land at Simonette in the liquids rich, over pressured Montney fairway T66 T65 KAKWA T64 WASKAHIGAN T63 XTO XTO T62 XTO XTO SIMONETTE XTO Land Legend T61 T60 T59 T58 T57 T56 Legend Apache Montney ARC Montney Athabasca Montney CIOC Montney CNRL Montney Cequence Montney Chevron Montney CPC Montney Delphi Montney Donnybrook Montney Encana Montney Enerplus Montney XTO Canada Montney Kelt Montney Lightstream Montney Nuvista Montney Paramount Montney RMP Montney 7G Montney Yoho All Rights XTO XTO XTO XTO RESTHAVEN XTO XTO XTO XTO XTO XTO Approximate Top Over Pressure FIR T55 XTO Hzntls Licensed since
5 Recent Highlights Sold 1,600 Boepd non operated asset for $141 million $135 million senior credit facility undrawn post asset sale Pad style development drilling now started at Simonette Increasing 2014 capital program to $170 million (net $23 million after divestitures) and $58 million in Q Target exit rate in March 2015 of 15,000 Boepd and $82 million net debt Production growth to over 40,000 Boepd by year end
6 Corporate Profile Trading Symbol TSX: CQE Q1 Production (Boe/d) 11,600 Q1 Cash flow $23 MM 52 week trading range $1.42 $3.21 Shares outstanding Insider ownership Market capitalization (1) July 2014 pro forma net cash balance (2) Debt capacity (3) Reserves P + P (4) 211 MM 13% FD $625 MM $10 MM $195 MM 109 MMBoe F, D & A (5) $11.17 per Boe Recycle Ratio on Q netback 2.4 times 6 (1) Based on Cequence stock price of $2.95 (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. Pro forma calculation includes estimated second quarter cash flow, capital expenditures and the disposition of the Ansell property on July 7, (3) Comprised of a $135 M senior credit facility and $60 M drawn CPPIB unsecured 5 year notes. (4) Pro forma Ansell Disposition effective July 1 (5) 2013 funding, development and acquisitions costs including future development costs calculated using proved plus probable reserves.
7 Corporate Guidance 2014 Q Average Production (Boe/d) 11,000 13,500 Exit production (Boe/d) 12,000 15,000 Capital expenditures, prior to dispositions (4) $170 MM $58 MM Capital expenditures, net of dispositions $23 MM $58 MM Wells drilled 19 (15.2) 6 (6.0) Operating and transportation costs per Boe $9.00 $8.20 Royalties (% of revenue) 10% 8% Crude oil WTI(US$/Bbl) $99.75 $97.00 Natural gas AECO(Cdn$/GJ) $4.60 $3.85 Funds flow from operations (2) $83 MM $27 MM Net debt and working capital deficiency (3) $51 MM $82 MM Basic shares outstanding 211 MM 211 MM 7 (1) Comprised of 84 percent 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. (4) Includes an estimated $24.1 million of capital expenditures in 2014 on the Ansell property prior to disposition.
8 Cequence Simonette Compressor Station Cequence Simonette Compressor Station 8
9 Simonette Project Infrastructure Ready for full scale development R2 R1W6 R27 R26 R25 R24 R23W5 T64 Cequence Alliance Meter Station Capacity 120 MMcf/d 3D Seismic Coverage Cequence owns and operates its facilities at Simonette Phase 6 Facility expansion planned in Q4 to 95 MMcfd T Field Compressor Trilogy Plant CQE W.I. = 25% Capacity 10 MMcf/d Potential for future additional expansion up to 100 MMcfd to TCPL. T Compressor Station Keyera Processing Facility Capacity 153 MMcf/d CQE GAS To Aux Sable To Aux Sable Deep Cut Plant Chicago, Illinois Simonette Area Q1 operating netback was $35 per Boe prior to hedging Facility Current Capacity 70 MMcf/d T61 T60 6 miles CQE Land 3D Seismic Outline CQE Gathering System Alliance Pipeline TCPL Pipeline Pembina Pipeline 9
10 Simonette Montney Drilling Plan through to Q R1W6 R27 R26 6 miles R25W5 Currently drilling first pad at 1 32, second pad at to spud in August T62 T61 OIL 100+ Bbls/MMcf PAD LOWER MONTNEY LOCATION 1 32 PAD 35 pad sites built or approved Gas condensate yields have increased to 27 Bbls per MMcf, 40 Bbls per MMcf of total NGLs T60 GAS (Avg 27 Bbls/MMcf Condensate) Cequence Land Montney Rights CQE Wells to Q CQE Montney Gas Well CQE Montney Oil Well Industry Montney Oil Well Industry Montney HZ Well 10
11 Simonette Upper Montney Development Plan Upper R1W6 R27 R26 6 miles R25W5 Approximately 200 locations depending on optimum well length CURRENT T62 HORIZONTAL TARGET ZONE OIL GAS 5 year plan will drill approximately 50% of current inventory Current planned interwell spacing 400 m Lower 2.3 TCF DPIIP (1) in Upper Montney T61 POTENTIAL HORIZONTAL TARGET ZONE Future plan to test the Lower Montney resource potential T60 (2) Cequence Land Montney Rights CQE Planned Wells CQE Montney Gas Well CQE Montney Oil Well Industry Montney Oil Well Industry Montney HZ Well 11 (1) See Forward Looking Information and Definitions for definition of DPIIP and total resource (2) Lower Montney porosity cut off 1% limestone based on petrographic analysis
12 Cequence Montney gas producers 19 wells to date Producing Daily Gas Rate (MMcf/d) CQE 7 BCF High Case CQE 5 BCF Base Case `HALF CYCLE ECONOMICS IP (MMcf/d) IP 30 (MMcf/d) EUR (MBoe) Raw Gas (Bcf) Condy (MBbl) NGL (MBbl) CAPEX $MM (D,C + TI) ROR BT (%) NPV $MM (10%) PAYOUT (YEARS) CAPITAL EFFICIENCY (1 st YEAR, $/Boed) BASE CASE Budget model ,000 HIGH CASE , , * Mechanical Complications Months on Production 12 Assumes 30 Bbls/MMcf of NGL s and condensate Assumes $4.00/GJ AECO, $90 WTI flat *Wells with mechanical complications included Includes 5% GORR, Opex $4.00 per Boe Gas rate does not include liquids
13 Montney Drilling and Completion Costs Long term target of $7.5 million is achievable $8,000 $7,000 Total $/m HZ Total $/m HZ includes pilot hole # of frac stages $6, $5, Total $/m HZ $4,000 $3, # of frac stages $2, $1, $ costs contain original well combined with re drill 9 21 completion costs was a re entry of an existing vertical uphole producer was a strat test with pilot hole and coring program
14 Simonette Dunvegan, Falher and Wilrich plays T63 T62 R2 R1W6 Wilrich R27 R26 R25W5 Dunvegan Oil and Gas/Condensate play 10 2 well 90 day IP was 13 MMcf/d 5 2 well 60 day IP was 9 MMcf/d Cequence has 11 net potential sections on trend Up to 25 BCF/sec resource potential T61 T60 Dunvegan 6 miles Falher Dunvegan Wilrich CQE Dunvegan/Falher Rights Vertical wells in trend Dunvegan HZ Gas Dunvegan HZ Oil Wilrich HZ Falher HZ Falher play First two CQE wells average 90 day IP of 5.5 MMcf/d with 21 bbls/mmcf condensate Cequence has mapped 28 potential locations on 14 net existing sections Analog pool produces 60 MMcf/d from 21 existing producers Wilrich play 20 net sections currently mapped with 40 potential locations 14
15 Dunvegan Model Daily Gas Rate (MMcf/d) W W6 CQE Working Model HALF CYCLE ECONOMICS IP (MMcf/d) IP 30 (MMcf/d) EUR (MBoe) Raw Gas (Bcf) Condy (MBbl) NGL (MBbl) CAPEX $MM (D,C + TI) ROR BT (%) NPV $MM (10%) PAYOUT (YEARS) CAPITAL EFFICIENCY (1 st YEAR, $/Boed) Working Model , Months on Production 15 Assumes 23 Bbls/MMcf of NGL s and condensate Assumes $4.00/GJ AECO, $90 WTI flat Year 1 Opex $2.00 per Boe Gas rate does not include liquids
16 Falher Model Daily Gas Rate (MMcf/d) W W6 CQE Working Model HALF CYCLE ECONOMICS IP (MMcf/d) IP 30 (MMcf/d) EUR (MBoe) Raw Gas (Bcf) Condy (MBbl) NGL (MBbl) CAPEX $MM (D,C + TI) ROR BT (%) NPV $MM (10%) PAYOUT (YEARS) CAPITAL EFFICIENCY (1 st YEAR, $/Boed) Working Model , Months on Production MODEL 16 Assumes 45 Bbls/MMcf of NGL s and condensate Assumes $4.00/GJ AECO, $90 WTI flat Year 1 Opex $2.00 per Boe Gas rate does not include liquids
17 Conclusions Simonette Project start of significant development drilling program to unlock this large resource play Financial strength strong balance sheet with $135 million undrawn bank facility through year end 2014 Team has a proven record of capturing large resource opportunities Highly experienced Board of Directors and Deep Basin Management team with significant ownership 17
18 Appendix Cequence Simonette Compressor Station 18
19 Management and Board Management Team Board of Directors Paul Wanklyn President and CEO Don Archibald Chairman Howard Crone Executive VP and COO Peter Bannister Steve Stretch VP Exploration and Chief Geophysicist Rob Cook Dave Gillis VP Finance and CFO Howard Crone Dave Robinson VP Exploration and Chief Geologist Brian Felesky James Jackson VP Engineering Daryl Gilbert Chris Soby VP Land and Corporate Development Frank Mele Mike Stewart VP Operations Paul Wanklyn Erin Thorson Controller James Gray Director Emeritus 19
20 Financial Highlights Q Q % Change Average Daily Production (Boe/d) 11,613 10, Funds flow from operations ($M) (1) $23,082 $14, Per share, basic and diluted $0.11 $ Operating costs per Boe $7.40 $ G&A per Boe $2.34 $ Capital expenditures, net ($M) $55,318 $51,531 7 Net debt and working capital (deficiency) ($M) (2) ($143,536) ($111,433) 29 Weighted average shares outstanding (diluted) (M) 210, ,917 0 (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, long term debt and excluding other liabilities 20
21 Production and Cash Costs 16,000 Production (Boe/d) $20 Cash Cost ($/Boe) 14,000 12,000 10,000 Merger with Temple Energy Includes Ansell disposition July 7 close Simonette will drive 44% growth to exit in 2015 $18 $16 $14 $12 8,000 6,000 4,000 2,000 Boe/d Total cash costs are in the top quartile of Canadian producers $10 $8 $6 $4 $2 $/Boe Est. Natural Gas Oil & NGL Q Est. $ Est. Cash Cost ($/Boe) Q Est. (1) Operating cost, transportation, G&A and Interest 21
22 Netback Table Q Simonette Corporate Total Average daily production (Boe/d) 8,263 11,612 Natural gas (MMcf/d) Oil and liquids (Bbls/d) 1,308 1,630 Sales price ($/Boe) $45.76 $44.29 Royalties ($/Boe) ($4.08) ($4.13) Operating cost ($/Boe) ($5.59) ($7.40) Transportation cost ($/Boe) ($1.13) ($1.52) Operating netback $34.96 $31.25 G&A ($/Boe) ($2.34) Interest ($/Boe) ($1.79) Cashflow netback ($/Boe) $22.14 Note: AECO C spot price of $5.59 CDN$/Mcf and WTI crude oil price of $98.65 US$/Bbl 22
23 Hedging Contract Type Volume GJ/d CAD Price 2014 July 1, 2014 to December 31, 2014 Average Gas Swap 30,000 $3.43/GJ AECO or $3.90/Mcf 2015 January 1, 2015 to March 31, 2015 Average Gas Swap 20,000 $3.79/GJ AECO or $4.32/Mcf 2015 April 1, 2015 to December 31, 2015 Average Gas Swap 10,000 $3.73/GJ AECO or $4.25/Mcf (1) Percentage calculated assuming current forecast production net of royalties and an estimated heat content 23
24 Reserves and Finding Costs solid growth per share in reserves and value $16.00 FD&A ($/Boe) 140 Reserves P Reserve Value 6 $ year average $11.61 per Boe Reserves increased % since Reserve value has doubled since 2010 $1,004 (1) $12.00 $10.00 $8.00 $6.00 $4.00 MMBoe Boe/share $MM $525 $715 $797 5 $/share 4 $ $ Proved + Probable (Incl FDC) Proved + Probable (2) Total Proved 2P per share Reserve Value 2P per share Proved + Probable GLJ Dec.31, (1) NPV10 (2) Pro forma Ansell disposition
25 Montney Half Cycle Economics 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: $90/Bbl WTI NPV 10% BT ($M) 10,000 5, Flat AECO Gas Price ($/MMBtu) 3.0 BCF + NGL's 5.0 BCF + NGL's 7.0 BCF + NGL's Notes: With 5% GORR, Oil $90/Bbl, C3 $31.5/Bbl,C4 $70/Bbl, C5+ $95/Bbl 25
26 Simonette Deep Basin Stack Dunvegan Wilrich Montney Simonette Upper Falher Bluesky / Gething CURRENT HORIZONTAL TARGET ZONE Simonette Lower POTENTIAL HORIZONTAL TARGET ZONE 26
27 Multiple Zones with Significant Resource Potential at Simonette CEQUENCE LAND 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 6 miles (1) See Forward Looking Information and Definitions for definition of total resource 27
28 Alberta Deep Basin Montney HZ First 6 month cumulative gas production Cum Gas (BCF) Average of CQE Wells 540 MMcf Average All Wells 390 MMcf Cequence Wells Industry Wells gas wells with production to Dec. 31, 2013, Geoscout data Oil wells excluded.
29 Alberta Deep Basin Montney HZ Drilling Analysis CQE among most efficient drillers and older 245 wells CQE P m/day All Wells P m/day Measured Depth (m) Meters drilled per day (m) wells CQE P m/day All Wells P m/day Measured Depth (m) Cequence Wells Competitor Wells Measured Depth Cequence Wells Competitor Wells Measured Depth Includes pilot wells, does not include re entries 29
30 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 tothe 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. Forward looking 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 andcashflow growth and the respective timing thereof; use of proceeds from the CPPIB Private Debt Placement; the Company's plan to not issue additional equity until year end 2018; 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 andcostsofoperating the Company s business; theabilityofthe Companytosecureadequate producttransportation; future oilandnaturalgas 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 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. 30
31 Forward Looking Statements or Information and Definitions Additional Advisories This presentation contains references to terms commonly used in the oil and gas industry. Netback is not defined by IFRS in Canada and is referred to as a non GAAP measure. Netbacks equal total revenue less royalties, operating costs and transportation costs. Management utilizes this measure to analyze operating performance. Funds flow from operations is a non GAAP term that represents cash flow from operating activities before adjustments for decommissioning liability expenditures and changes in working capital. The Company evaluates its performance based on earnings and funds flow from operations. The Company considers funds flow from operations to be a key measure as it demonstrates the Company's ability to generate the cash flow necessary to fund future growth through capital investment and to repay debt. The Company's calculation of funds flow from operations may not be comparable to that reported by other companies. Funds flow from operations per share is calculated using the sameweighted averagenumber of sharesoutstanding used in the calculation of income (loss) per share. "Total resources" are that quantity of petroleum that is estimated to exist originally in naturally occurring accumulations. Total resources include 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 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. "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, thereshould be atleasta50percentprobability (P50) thatthe quantities actually recovered will equal or exceed the best estimate. The foregoing outlook and guidance has been provided to assist investors in analyzing the Company s anticipated development strategies and prospects and it may not be appropriate for other purposes and actual results could differ from the guidance provided above. Cequence refers to initial production rates which may not be indicative of long term well performance. BOEs are presented on the basis of one BOE for six Mcf of natural gas. Disclosure provided herein in respect of BOEs may be misleading, particularly if used in isolation. A BOE conversion ratio of 6 Mcf:1 Bbl is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead. For the three months ended March 31, 2014, the ratio between the average price of West Texas Intermediate ( WTI ) crude oil at Cushing and NYMEX natural gas was approximately 21:1 ( Value Ratio ). The Value Ratio is obtained using the first quarter 2014 WTI average price of $98.65 (US$/Bbl) for crude oil and the first quarter 2014 NYMEX average price of $4.72 (US$/MMbtu) for natural gas. This Value Ratio is significantly different from the energy equivalency ratio of 6:1 and using a 6:1 ratio would be misleading as an indication of value. 31
32 3100, 525-8th Avenue SW Calgary AB T2P 1G1 Phone: Fax: Contacts: Paul Wanklyn President & CEO energy.com David Gillis Vice President, Finance & CFO energy.com
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