Annual General Meeting May 21, cequence. energy ltd

Transcription

1 Annual General Meeting May 21, 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 31 "Forward-Looking Statements or Information and Definitions." 2

3 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 3

4 Focus in the Deep Basin of Alberta Cequence is positioned to become a significant natural gas producer in Canada with two large projects now established: Simonette Project is ready for accelerated development CANADA USA Ansell Project now on stream > 1.0 TCF potentially recoverable in multiple stacked formations at these two projects Strong financial capacity SIMONETTE PROJECT Low cost operations with facilities in place 5 year plan to grow production to over 40,000 Boepd Deep Basin ANSELL PROJECT 4

5 Recent Highlights Q1 cashflow reached a record $23 million on production of 11,600 Boepd Yearend 2P reserves grew 24% to 113 Mmboe with NPV 10% of $1 billion 2P FD&A was $11.17 per boe, F&D was $10.10 per Boe Bank line of credit has been recently approved at $155 million, up from $120 million previously Ansell Wilrich Project is now on production through new facilities completed in April 5

6 Corporate Profile Trading Symbol TSX: CQE Q1 Production (Boe/d) 11,600 Q1 Cashflow $23 million 52-week trading range $ $3.15 Shares outstanding Insider ownership Market capitalization (1) March 31, 2014 net debt (2) Debt capacity (3) Reserves P + P F,D&A (4) Recycle Ratio on Q netback 211 million 13% FD $570 million $143 million $215 million 113 mmboe $11.17 per boe 2.4 times (1) Based on Cequence stock price of $2.70 (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) Comprised of a recently approved $155 M senior credit facility and $60 M drawn CPPIB unsecured 5 year notes. (4) 2013 funding, development and acquisitions costs including future development costs calculated using proved plus probable reserves. 6

7 Guidance - 40% growth planned for Preliminary 2014 Guidance (4) Production (Boe/d) 10,183 (1) 13,500-14,000 Exit production (Boe/d) 12,000 15,000 Capital expenditures $111 MM $120 MM Wells drilled 15 (11.75) 16 (14) Operating costs per Boe $7.00 $6.85 Royalties (% of revenue) 8% 9% Crude oil WTI (US$/Bbl) $98.01 $95.75 Natural gas AECO (Cdn$/GJ) $3.17 $3.50 Funds flow from operations (2) $51.3 MM $85 MM Year end net debt and working capital deficiency (3) $111 MM $145 MM Basic shares outstanding MM MM 7 (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, demand credit facilities and the aggregate principal amount of the Notes and excluding other liabilities. (4) October, 2013

8 5 Year Development Plan 80% of drilling is assumed to be Montney at Simonette Major Assumptions: NO ADDITIONAL EQUITY 143 wells drilled in next five years (80% Montney, 20% other zones) Base Case Montney production model and $8 million cost per well Facilities and maintenance capital - $14 MM/yr, Land/seismic - $9 MM/yr Conservative debt level achieved on strip gas price 5 year plan does not incorporate recent success at Ansell 8

9 Cequence Simonette Compressor Station Cequence Simonette Compressor Station 9

10 Simonette Project Infrastructure -ready for full scale development Cequence Alliance Meter Station Capacity 120 MMcf/d Facility - Current Capacity 70 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 Camp and drilling rigs will run on natural gas Simonette Area Q1 operating netback was $35 per Boe prior to hedging Current facility ready for expansion to 120 MMcfd through Alliance Potential for future additional expansion up to 100 MMcfd to TCPL. 6 miles 10

11 Alberta Deep Basin Montney Competitor Lands Cequence owns 87 net sections of Montney land at Simonette in the liquids rich, over-pressured Montney fairway Significant drilling activity on adjacent lands 11

12 Montney Liquids Three important wells completed in Q1 reinforce transition to development style pad drilling 23 pads currently built with pipeline tie-ins 12 additional pads approved for construction Higher liquids yield on the west side of Simonette and average condensate yield now 27 Bbls per MMcf miles 12

13 Simonette Montney Development Plan Approximately 200 locations depending on optimum well length 5 year plan will drill approximately 50% of current inventory Current planned interwell spacing 400 m. 2.3 TCF DPIIP (1) in Upper Montney Future plan to test the Lower Montney resource potential 6 miles 13 (1) See Forward-Looking Information and Definitions for definition of DPIIP and total resource

14 Cequence Montney gas producers - 18 wells to date Producing Daily Gas Rate (MMcf/d) `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 , , Months CQE 5 BCF Base Case CQE 7 BCF High Case 14 Assumes 30 Bbls/MMcf of NGL s and condensate Assume $4.00/GJ AECO, $90 WTI flat Wells with mechanical failures included Includes 5% GORR, Opex $4.00 per Boe Gas rate does not include liquids

15 Montney Drilling and Completion Costs -Long term target of $7.5 million is achievable $7 Montney Drilling Costs 4500 $6 Montney Completion Costs $900 $ $5 $750 Drill Costs $MM $5 $4 $3 $ HZ length drilled (m) Completion Costs $MM $4 $3 $2 $600 $450 $300 $M per Frac Stage $1 $ / / / /14 Drilling cost HZ length drilled Est Est $1 $ $0 2010/ / / / Est Est. Completion cost Frac cost per stage # of stages $ 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

16 Simonette Dunvegan, Falher and Wilrich plays Area average: IP rate 4.5 MMcf/d Reserves 4.0 BCF and Bbl/MM NGL 6 miles Model: IP rate 6.5 MMcf/d Reserves 5 BCF and Bbl/MM NGL 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 sections along gas and oil trend Up to 25 BCF/sec resource potential 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 Nearby Resthaven pool has excellent production history 16

17 Ansell Wilrich Project Pipeline To Talisman Edson Gas Plant W5 Facility Initial de-risking of project successful 100 MMcf/d pipeline and 40 MMcf/d Phase 1 compressor/dehydration facility completed in April wells now on stream Cequence owns 49% WI in a large contiguous land block and production facilities 6 miles 17

18 Conclusions Simonette Project large proven Deep Basin Montney resource play with multiple uphole zones Ansell project Wilrich resource play in an excellent area Financial strength - CQE has a strong balance sheet with $70 million of available credit facilities Highly experienced Board of Directors and Deep Basin Management team with significant ownership 18

19 Appendix 19 Cequence Simonette Compressor Station

20 Canada Pension Plan Investment Board Private Debt Placement $60 million, 5 year unsecured notes issued at par Closed on October 3 rd, 2013 Coupon rate 9%, plus 3.0 million warrants at $2.03 Initially used to pay down outstanding bank debt Second tranche of $60 million available subject to approval of both CPPIB and CQE Cequence has additional financial flexibility consisting of: Undrawn bank facility of approximately $120 million Optional $60 million of second tranche CPPIB notes 20

21 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 21

22 Production and Cash Costs 16,000 14,000 12,000 10,000 Production (Boe/d) Merger with Temple Energy Simonette and Ansell Projects will drive 40% growth in 2014 $20 $18 $16 $14 $12 Total Cash Costs ($/Boe) (1) 8,000 6,000 Boe/d $10 $8 $/Boe 4,000 2,000 Total cash costs are in the top quartile of Canadian producers $6 $4 $ Est. $ Est. Natural Gas Oil & NGL (1) Operating cost, transportation, G&A and Interest 22

23 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 23

24 Hedging Contract Type Volume GJ/d CAD Price 2014 January 1, 2014 to December 31, 2014 Average Gas Swap 30,000 $3.45/GJ AECO or $4.00/Mcf 2015 January 1, 2015 to March 31, 2015 Average Gas Swap 20,000 $3.79/GJ AECO or $4.40/Mcf 2015 April 1, 2015 to December 31, 2015 Average Gas Swap 10,000 $3.73/GJ AECO or $4.32/Mcf (1) Percentage calculated assuming current forecast production net of royalties and an estimated heat content 24

25 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 $11.61per Boe 120 Reserves increased 130% since Reserve value has doubled since 2010 $1,036 $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 Total Proved 2P per share Reserve Value 2P per share Proved + Probable GLJ Dec.31,

26 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 26

27 Simonette Deep Basin Stack Dunvegan Wilrich Montney 2950 Simonette Upper 2975 CURRENT HORIZONAL TARGET ZONE Falher Bluesky / Gething Simonette Lower 3050 POTENTIAL HORIZONAL TARGET ZONE

28 Multiple Zones with Significant Resource Potential at Simonette 6 miles 2,400m 2,500m 2,700m Zone Dunvegan Falher Wilrich Total Resource Potential/Sec (1) 5-25 BCF 5-24 BCF 5-24 BCF 2,800m Gething 5-25 BCF 2,950m 3,100m Upper Montney BCF 28 (1) See Forward-Looking Information and Definitions for definition of total resource

29 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.

30 Alberta Deep Basin Montney HZ Drilling Analysis CQE among most efficient drillers and older 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 30

31 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. 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 and cash flow 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 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 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. 31

32 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 same weighted average number of shares outstanding 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, there should be at least a 50 percent probability (P50) that the 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. 32

33 3100, 525-8th Avenue SW Calgary AB T2P 1G1 Phone: Fax: Contacts: Paul Wanklyn President & CEO David Gillis Vice President, Finance & CFO