National Bank Financial 2014 Intermediate Energy Growth and Yield Conference February 2014 Toronto. cequence. energy ltd

Transcription

1 National Bank Financial 2014 Intermediate Energy Growth and Yield Conference February 2014 Toronto 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 [32] "Forward Looking Statements or Information and Definitions." 2

3 Focus in the Deep Basin of Alberta Cequence is positioned to become a significant natural gas producer in Canada Simonette Project is ready for accelerated development BRITISH COLUMBIA ALBERTA CANADA USA Ansell Project has expanded rapidly > 1.0 TCF potentially recoverable in multiple stacked formations at these two projects Strong financial capacity PEACE RIVER SIMONETTE PROJECT Low cost operations with facilities in place or under construction 5 year plan to grow production to over 40,000 Boepd Deep Basin GRANDE PRAIRIE ANSELL PROJECT EDMONTON 3

4 Corporate Profile Trading Symbol TSX: CQE Current Production (Boe/d) 12, week trading range $1.27 $1.97 Shares outstanding Insider ownership Market capitalization (1) September 30, 2013 net debt (2) Debt capacity (3) 211 million 13% FD $350 million $73 million $180 million 4 (1) Based on Cequence stock price of $1.65 (2) Net debt is calculated as net working capital less commodity contract asset and liabilities and demand credit facilities, long term debt and excluding other liabilities. (3) Comprised of $120 M senior credit facility and $60 M drawn CPPIB unsecured 5 year notes.

5 Recent Highlights Simonette facility expansion completed 70 mmcfd current capacity Montney producing unrestricted at 7.7 MMcfd 1 21 and 2 21 Montney wells initial remediation successful Recent Dunvegan well producing at 10 MMcfd and 300 Bbls per day condensate Ansell Wilrich Project has emerged as an exciting new opportunity for Cequence Land position has increased to 46.5 gross sections 5 gross wells planned in Q1 40 mmcfd facility constructed in Q1 5

6 Guidance 40% growth planned for Guidance Preliminary 2014 Guidance Production (Boe/d) 10,000 (1) 13,500 14,000 Exit production guidance (Boe/d) 12,000 15,000 Capital expenditures $110 MM $120 MM Wells drilled 16 (13.8) 16 (14) Operating costs per Boe $7.00 $6.85 Royalties (% of revenue) 9% 9% Crude oil WTI (Cdn$/Bbl) $95.75 $95.75 Natural gas AECO (Cdn$/GJ) $3.00 $3.50 Funds flow from operations (2) $50 MM $85 MM Year end net debt and working capital deficiency (3) $110 MM $145 MM Basic shares outstanding MM MM 6 (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.

7 Production and Cash Costs 16,000 14,000 12,000 10,000 8,000 6,000 Production (Boe/d) Merger with Temple Energy Boe/d Simonette and Ansell Projects will drive 40% growth in 2014 $20 $18 $16 $14 $12 $10 $8 Total Cash Costs ($/Boe)* $/Boe 4,000 2,000 Total cash costs are in the top quartile of Canadian producers $6 $4 $ Est Est. $ Est Est. Natural Gas Oil & NGL *Operating cost, transportation, G&A and Interest 7

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 8

9 Simonette Project Infrastructure Expansion completed (13 11 capacity increased to 70 mmcfd) R2 R1W6 R27 R26 R25 R24 R23W5 Large land position T64 Cequence Alliance Meter Station Capacity 120 MMcf/d 3D Seismic Coverage 87 net sections of Montney rights 156 net sections of Cretaceous rights T63 T Compressor Station 9 10 Field Compressor Trilogy Plant CQE W.I. = 25% Capacity 10 MMcf/d Keyera Processing CQE GAS To Aux Sable 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 Facility Expanded Capacity 70 MMcf/d Simonette Area 2013 operating costs were $5.30 per Boe resulting in a field netback of $20.45 per Boe T61 T60 6 miles CQE Land 3D Seismic Outline CQE Well CQE Field Compressor CQE Gathering System Alliance Pipeline 9

10 Alberta Deep Basin Montney Competitor Lands R9 R8 R7 R6 R5 R4 R3 R2 R1W6 R26 R25 R24 R23 R22 R21W5 T69 T68 T67 WAPITI KARR ANTE CREEK Cequence owns 87 net sections of Montney land at Simonette in the liquids rich, over pressured Montney fairway T66 T65 T64 KAKWA WASKAHIGAN Numerous active operators T63 XTO XTO T62 T61 T60 T59 T58 T57 T56 T55 Land Legend 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 Hzntls Licensed 2013 XTO XTO XTO XTO RESTHAVEN XTO XTO XTO XTO XTO SIMONETTE XTO XTO Approximate Top Over Pressure FIR 10

11 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 11 (1) 137 gas wells with production to Dec. 31, 2013, Geoscout data (2) Oil wells excluded.

12 Simonette Montney 2014 Winter Drilling Plan Proven Large Scale Economic Resource Play R2 R1W6 R27 R26 R25W5 Current Focus: T62 Location W5 1) Transition to development style pad drilling 2) Continue to expand the resource base with exploration/exploitation wells 3) Proving production model current rate is 7.7 MMcfd GAS OIL T (5 fracs) 2.9 MMcfd 2 21 (6 fracs) 2.1 MMcfd Successful first phase remediation completed 1 21 (5 of 28 frac stages now completed) T Drilling 6 miles Cequence Land Montney Rights CQE Planned Wells CQE Montney Gas Well CQE Montney Oil Well Industry Montney Oil Well Industry Montney HZ Well 2 21 (6 of 28 frac stages now completed). Evaluating additional remediation for Q3 12 (1) See Forward Looking Information and Definitions for definition of DPIIP and total resource

13 Simonette Montney Development Plan R2 R1W6 R27 R26 R25W locations depending on optimum well length T62 5 year plan will drill approximately 50% of current inventory Current planned inter well spacing 400 m. GAS OIL 2.5 TCF DPIIP (1) in Upper/middle Montney T61 T60 6 miles Cequence Land Montney Rights CQE Planned Wells CQE Montney Gas Well CQE Montney Oil Well Industry Montney Oil Well Industry Montney HZ Well 13 (1) See Forward Looking Information and Definitions for definition of DPIIP and total resource

14 Cequence Montney gas producers 14 wells to date Producing Daily Gas Rate (MMcf/d) Montney Wells W W W W W W5 `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 (1) Assumes 30 Bbls/MMcf of NGL s and condensate (2) Assume $3.20 AECO esc. 5% /yr, $90 WTI flat (3) Includes 5% GORR, Opex $4.00 per Boe (4) Gas rate does not include liquids

15 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 15 (1) With 5% GORR * Oil $90/Bbl, C3 $31.5/Bbl,C4 $70/Bbl, C5+ $95/Bbl

16 16 Montney Drilling and Completion Costs steady improvement in cost over time 7 Montney Drilling Costs Montney Completion Costs Drill & Completion Costs $M Meters drilled Completion Costs $MM $M per Frac Stage Target = $4.2MM Target = $2.75MM Drill Costs $MM HZ length drilled (m) 2010/ / / /14 Drilling cost HZ length drilled 2010/ / / /14 Completion cost Frac cost per stage # of stages * 8 21 costs contain original well combined with re drill 9 21 completion costs

17 Simonette Dunvegan Oil, and Gas/Condensate Play R3 R2 R1W6 R27 R26 R25W5 T62 Area average: IP rate 4.5 MMcf/d Reserves 4.0 BCF and Bbl/MM NGL Competitor Location 10 2 well 90 day IP was 13 MMcf/d 5 2 well currently producing at restricted rates T61 RESTHAVEN POOL SIMONETTE OIL POOL 42 API Cequence has 11 net existing sections along gas and oil trend T HZTL On production mid January at 10 MMcfd and 300 Bbls/d of condensate restricted 6 miles Cequence Land Dunvegan Rights Vertical Dunvegan Channel Completion Industry Dunvegan HZ Well Up to 25 BCF/sec resource potential (1) Average GORR = 0% (2) Assume $3.20 AECO, esc. 5% /yr, $90 WTI flat 17

18 Simonette Falher Play R2 R1W6 R27 R26 R25W5 T62 Model: IP rate 6.5 MMcf/d Reserves 5 BCF and Bbl/MM NGL HALF CYCLE ECONOMICS IP (MMcf/d) IP 30 (MMcf/d) EUR (MBoe) Raw Gas (BCF) Condy (MBbl) NGL (MBbl) Model First two CQE wells average 90 day IP of 5.5 MMcf/d with 21 Bbls/MMcf condensate CAPEX $MM (D,C + TI) ROR BT (%) NPV $MM (10%) PAYOUT (YEARS) CAPITAL EFFICIENCY (1 st YEAR, $/Boed) ,000 Cequence has mapped 28 potential locations on 14 net existing sections T61 Analog pool produces 60 MMcf/d from 21 existing producers T60 6 miles Cequence Land Falher Rights CQE Falher HZ Production Falher F Vertical Production 18 (1) Average GORR = 0% (2) Assume $3.20 AECO, esc. 5% /yr, $90 WTI flat (3) Model based on Musreau pool

19 Simonette Wilrich Play R2 R1W6 R27 R26 R25 R24W5 T63 T62 WILRICH POOL `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) Model , net sections currently mapped with 40 potential locations Deeper Montney drilling has confirmed the geological extension of the existing Wilrich trend to the south T61 Deeper Montney exploitation drilling confirms Wilrich pay extension to south location drilled and waiting on completion T60 T59 RESTHAVEN WILRICH POOL 6 miles Waiting on Completion Cequence Land Wilrich Rights Wilrich 2014 location CQE Wilrich Gas Well Industry Wilrich Well Wilrich Pay In Montney Tests Nearby Resthaven pool has excellent production history 19 (1) Average GORR = 7.5% (2) Assume $3.20 AECO, esc. 5% /yr, $90 WTI flat

20 Ansell/Edson Wilrich Project Expanding land position R20 T52 T51 R19 PEYTO R18 PERPETUAL TOURMALINE TALISMAN R17 Pipeline To Talisman Edson Gas Plant W5 Phase 1 Comp/Dehy Facility Capacity = 40 MMcfd PERPETUAL R16W5 CQE day IP rate 5.9 MMcf/d restricted First two Cequence wells producing above type curve Two rigs currently drilling 5 additional wells in Q1 Cequence now owns 46 sections of land and will retain a 49% WI in the Ansell project after completion of the 8 well farmout to JV partner 100 MMcfd pipeline and 40 MMcfd Phase 1 compressor/dehydration facility expected completion in Q Waiting on Completion T50 ENERPLUS CONOCO 20 T49 TOURMALINE HUSKY Drilling CEQUENCE Drilling CQE day IP rate 6.3 MMcf/d restricted CQE Land Wilrich Rights CQE Wilrich Wells Wilrich Wells Daily Producing Gas Rate (MMcf/d) Cequence Edson Wilrich HZ Months on Production Model (5.0 IP, 5 bcf) W W5

21 Conclusions Simonette Project proven large economic resource play in multiple zones Ansell project exciting drilling program and facilities construction in this new core area Financial strength CQE has a strong balance sheet with $60 million of 5 year term debt Highly experienced Board of Directors and Deep Basin Management team with significant ownership 21

22 Appendix 22 Cequence Simonette Compressor Station

23 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 23

24 Management and Board Management Team Paul Wanklyn President and CEO Howard Crone Executive VP and COO Dave Gillis VP Finance and CFO Steve Stretch VP Exploration and Chief Geophysicist Dave Robinson VP Exploration and Chief Geologist James Jackson VP Engineering Chris Soby VP Land and Corporate Development Mike Stewart VP Operations Erin Thorson Controller Board of Directors Don Archibald Chairman Peter Bannister Rob Cook Howard Crone Brian Felesky Daryl Gilbert Frank Mele Paul Wanklyn James Gray Director Emeritus 24

25 Financial Highlights Q Q % Change Average Daily Production (Boe/d) 10,292 11,205 (8) Funds flow from operations ($M) (1) $10,973 $14,831 (26) Per share, basic and diluted $0.05 $0.07 (29) Operating costs per Boe $8.29 $ G&A per Boe $2.02 $2.14 (6) Capital expenditures, net ($M) $17,944 $2, Net debt and working capital (deficiency) ($M) (2) ($72,984) ($66,001) 11 Weighted average shares outstanding (diluted) (M) 210, ,767 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, long term debt and excluding other liabilities 25

26 Netback Table YTD Sept 2013 Simonette Corporate Total Average daily production (Boe/d) 6,634 10,112 Natural gas (MMcf/d) Oil and liquids (Bbls/d) 1,045 1,368 Sales price ($/Boe) $28.72 $27.94 Royalties ($/Boe) ($2.29) ($2.48) Operating cost ($/Boe) ($4.95) ($7.78) Transportation cost ($/Boe) ($1.44) ($1.60) Operating netback $20.05 $16.08 G&A ($/Boe) ($2.06) Interest ($/Boe) ($0.63) Cashflow netback ($/Boe) $13.39 Note: Year to date AECO C spot price of $3.07 CDN$/Mcf and WTI crude oil price of $98.09 US$/Bbl 26

27 Hedging Contract Type Volume GJ/d CAD Price 2013 July 1, 2013 to December 31, 2013 Average Gas Swap 24,500 $3.15/GJ AECO or $3.65/Mcf 50% remaining 2013 natural gas 2014 January 1, 2014 to December 31, 2014 Average Gas Swap 30,000 $3.44/GJ AECO or $4.00/Mcf 50% of 2014 gas (1) (1) Percentage calculated assuming current forecast production net of royalties and an estimated heat content 27

28 Net Asset Value (NAV) April 30, 2013 GLJ Report Proved + Probable, NPV 10% 1,052,742 Land (1) 101,000 Net Debt, September 30, 2013 (73,000) (2) NAV 1,084,741 $M Shares Outstanding (M) 210,900 NAV/Share ($/share) 5.12 (1) Internal estimate (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. 28

29 Reserves and Finding Costs solid growth per share in reserves and value $16.00 $14.00 FD&A ($/Boe) 3 year average $12 per Boe Reserves Reserves increased 130% in last 3 years P Reserve Value Reserve value has doubled in last 3 years $ $12.00 $10.00 $8.00 $6.00 $4.00 MMBoe Boe/share $MM $525 $715 $797 5 $/share 4 $ $ Proved + Probable (Incl FDC) Q Proved + Probable Total Proved 2P per share Q Reserve Value 2P per share Proved + Probable GLJ April 13,

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

31 Multiple Zones with Significant Resource Potential at Simonette 6 miles 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 (1) See Forward Looking Information and Definitions for definition of total resource 31

32 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 32

33 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. 33

34 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 second quarter of 2013, the ratio between the average price of West Texas Intermediate ("WTI") crude oil at Cushing and NYMEX natural gas was approximately 25:1 ("Value Ratio"). The Value Ratio is obtained using the first quarter 2013 WTI average price of $94.22(US$/Bbl) for crude oil and the second quarter 2013 NYMEX average price of $3.75(US$/MMbtu) for natural gas. This Value Ratio is significantly different from the energy equivalency ratio of 6:1 and using a 6:1ratiowouldbe misleading as an indication of value. 34

35 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