EPAC Oil & Gas. Investor Showcase. June, 2013 RESOURCE FOCUS OPPORTUNITY SUSTAINABILITY

Transcription

1 EPAC Oil & Gas Investor Showcase June, 2013 RESOURCE FOCUS OPPORTUNITY SUSTAINABILITY

2 Cautionary Statement This presentation contains certain forward looking information and statements within the meaning of applicable securities laws. The use of any of the words "expect", "anticipate", "continue", "estimate", "may", "will", "project", "should", "believe", "plans", "intends" and similar expressions are intended to identify forward-looking information or statements. In particular, but without limiting the forgoing, this presentation contains forward-looking information and statements pertaining to the following: the volumes and estimated value of Crew's oil and gas reserves; resource estimates and volumes in respect of Crew s Montney lands in N.E.B.C.; the volume of Crew's oil and gas production; future oil and natural gas prices and Crew's commodity risk management programs; future liquidity and financial capacity; future results from operations and operating metrics; future costs, expenses and royalty rates; future interest costs; the exchange rate between the $US and $Cdn; future development, exploration, acquisition and development activities and related capital expenditures; the amount and timing of capital projects; operating costs; the total future capital associated with development of reserves and resources; and forecast reductions in operating expenses. The recovery, reserve and resources estimates of Crew's reserves and resources provided herein are estimates only and there is no guarantee that the estimated reserves or resources with be recovered. In addition, forward-looking statements or information are based on a number of material factors, expectations or assumptions of Crew which have been used to develop such statements and information but which may prove to be incorrect. Although Crew believes that the expectations reflected in such forward-looking statements or information are reasonable, undue reliance should not be placed on forward-looking statements because Crew can give no assurance that such expectations will prove to be correct. In addition to other factors and assumptions which may be identified herein, assumptions have been made regarding, among other things: the impact of increasing competition; the general stability of the economic and political environment in which Crew operates; the timely receipt of any required regulatory approvals; the ability of Crew to obtain qualified staff, equipment and services in a timely and cost efficient manner; drilling results; the ability of the operator of the projects in which Crew has an interest in to operate the field in a safe, efficient and effective manner; the ability of Crew 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 and exploration; risks associated with the degree of certainty in resource assessments; the timing and cost of pipeline, storage and facility construction and expansion and the ability of Crew to secure adequate product transportation; future commodity prices; currency, exchange and interest rates; regulatory framework regarding royalties, taxes and environmental matters in the jurisdictions in which Crew operates; and the ability of Crew to successfully market its oil and natural gas products. The forward-looking information and statements included in this presentation are not guarantees of future performance and should not be unduly relied upon. Such information and statements; including the assumptions made in respect thereof, involve known and unknown risks, uncertainties and other factors that may cause actual results or events to defer materially from those anticipated in such forward-looking information or statements including, without limitation: changes in commodity prices; changes in the demand for or supply of Crew's products; unanticipated operating results or production declines; changes in tax or environmental laws, royalty rates or other regulatory matters; changes in development plans of Crew or by third party operators of Crew's properties, increased debt levels or debt service requirements; inaccurate estimation of Crew's oil and gas reserve and resource volumes; limited, unfavourable or a lack of access to capital markets; increased costs; a lack of inadequate insurance coverage; the impact of competitors; and certain other risks detailed from time-to-time in Crew's public disclosure documents, (including, without limitation, those risks identified in this presentation and Crew's Annual Information Form). The forward-looking information and statements contained in this presentation speak only as of the date of this presentation, and Crew does not assume any obligation to publicly update or revise any of the included forward-looking statements or information, whether as a result of new information, future events or otherwise, except as may be required by applicable securities laws. BOE equivalent Barrel of oil equivalents or 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. Given that the value ratio based on the current price of crude oil as compared to natural gas is significantly different than the energy equivalency of the 6:1 conversion ratio, utilizing the 6:1 conversion ratio may be misleading as an indication of value. 2

3 Focus on Growth and Resource Capture B.C. Alberta Sask. Montney NGL Rich Gas/Oil Cardium/Falher NGL Rich Gas Princess Lloydminster Operating Strategy Resource Capture Target reservoirs with large hydrocarbon storage capacity Exploration Proof of concept Exploitation Commit capital to areas with growth potential and superior economics Execution of Strategy 76 TCFE Montney resource (TPIIP) 2013 forecasted average production of 27,500-28,500 boepd Exit 2013 forecasted production 29,000-30,000 boepd 1,018,521 net acres of land (72% undeveloped) >2,500 drilling locations 373 sections of Montney Rights controlled in N.E.B.C. Crew Resource Plays Crew Land 3

4 2012 Highlights Production (boepd) 27,963 25% Reserves (mmboe) % F,D & A (2P) ($boe) % Recycle Ratio % 2P RLI (years) % Debt ($mm) % 2P NAV vs current price of $6.00 ($/SH) % Signed agreements to sell 23 Montney sections for $108 million and purchase 200 sections for $78 million Successful application of new completion technology at Septimus increasing 2P reserves by 44% and reducing well costs by $500 m/well Increased Deep Basin production by 25% and 2P reserves by 55% Successful application of horizontal well technology to thin oil reservoirs at Lloydminster Initiated six new waterfloods at Princess Proved new play concept in Mannville at Princess 4

5 Total Boepd Production Per Diluted Share Production Growth ,963 28,000 29, % Sold 1,700 boepd for $126 mm 22, ,002 13, ,696 11, ,500 2,428 4,093 5, Sept ' (Est.) Oil & NGL Gas Production Per Diluted share 2013 (Exit Est.) 0 5

6 Total mboe Reserves per outstanding share Reserves Summary , % , , ,124 65, , ,716 Dec ,341 Dec ,144 Dec ,116 Dec Dec Dec Dec Dec Dec Dec Liquids Gas Proved + Probable Reserves Per Outstanding Share 6

7 Crew Share Price Performance 7

8 2013 Forecast Cashflow from Operations (CF) $182 mm CF/diluted share $ 1.49 Net E&D Capex $220 mm Year-end debt $378 mm Debt to annualized Q4 CF 1.9x Assumptions: Production guidance (boe/d) 27,500-28,500 Pricing Gas (AECO-C$/mcf) 3.50 Oil (WTI-CDN$/bbl) FX ($US/$CDN) 0.98 WTI to WCS differential 24% Royalties 21% Op. costs ($/boe) Transportation ($/boe) 1.40 G&A ($/boe) 1.80 Interest ($/boe)

9 2013 Hedging Summary Volume Period Derivative Reference Price Natural Gas 5,000 GJ/Day 2013 Collar AECO $2.65 x $3.50 5,000 GJ/Day Apr. to Oct Collar AECO $3.39 x $ ,500 GJ/Day 2013 Swap AECO $ ,500 GJ/Day (49% of budget volume) $3.01 $3.22/mcf Oil 5,500 bopd (38% of budget volume) 2013 Swap C$WTI $ ,200 bopd Q Swap C$WCS-WTI -$ ,500 bopd Q Swap C$WCS-WTI -$ ,000 bopd Q Swap C$WCS-WTI -$

10 76 TCFE Montney Resource Purchase Option Land Portage Crew Land Septimus/Groundbirch Purchase Attachie/Goose Purchase Crew Operated Pipeline TCPL Conceptual Pipeline Route Alliance Operated Pipeline Spectra Westcoast Pipelines Goose 84 Miles 292 net sections of Montney resource 33.7 TCF natural gas resource 7 billion barrels oil resource (42 TCFE) 3 TCFE best estimate contingent resource TCFE booked reserves WET GAS WINDOW Attachie OIL WINDOW Flatrock Septimus 40 Miles Groundbirch Crew operated Septimus gas plant Tower Alliance Septimus meter station Crew new HZ locations Portage Crew operated pipeline Dry Gas Window = >95% C1, (< 10 bls/mmcf NGL s) Oil Window = <50 API Oil Sections: 134 (36%) Wet Gas Sections: 163 (44%) Dry Gas Sections: 76 (20%) Total Sections: 373 Includes Option Lands (81 sections) Resource estimates are based on an independent evaluation by Sproule Associates effective May 1, 2013 prepared in accordance with the COGE Handbook. See Appendix for additional details, definitions and advisory statements. Natural Gas Resource Categories Resource (TCF) Total Petroleum Initially In Place (TPIIP) 33.7 Discovered Petroleum Initially In Place (DPIIP) 12.0 Undiscovered Petroleum Initially in Place (UPIIP) 21.7 Oil Resource Categories Resource (MMBBL) Total Petroleum Initially In Place (TPIIP) 7,031.5 Discovered Petroleum Initially In Place (DPIIP) Undiscovered Petroleum Initially in Place (UPIIP) 6,

11 Montney Comparative Area Economics Land List Industry Held Montney Land Crew Land 1 4 Fort St. John Septimus Septimus Grand Prairie Montney Gas Fields 6 1. Altares/Caribou/Farrell/ Kobes/Town/Lily 2. Groundbirch/Sundown/ Swan/Tupper 3. Dawson/Monias/Saturn/ Sunrise/Sunset 4. Parkland/Septimus/ Tower 5. Glacier/Pouce Coupe 6. Elmworth/Gold Creek/ Wapiti 7. Kakwa/Karr/Resthaven/ Simonette 8. Kaybob/Bigstone/Fir Source: RBC Capital Markets 7 8 IRR Natural Gas Supply Cost Area 4 Septimus Source: RBC Capital Markets Area 3 Dawson Area 6 Elmworth Area 8 Kaybob Area 7 Kakwa Area 2 Groundbirch Area 1 Altares Area 5 Glacier Area 4 Septimus Source: RBC Capital Markets Area 3 Dawson Area 6 Elmworth Area 8 Kaybob Area 7 Kakwa Area 2 Groundbirch Area 1 Altares Area 5 Glacier 11

12 mcfd Septimus Lower Montney Devon 7-30 Cum: 2.7 Bcf Curr: 2.0 mmcf/d Multi-zone Montney Moderate-highly overpressured (14 kpa/m) Liquids rich gas (Average 28 bbls/mmcf) Average depth 1,750 m Upper Montney thickness 135 m Crew 100% pipeline Crew B4-2, 8.2 mmcf/d after 10 days Crew D4-2, 6.6 mmcf/d after 14 days Crew 1-34 Pad Crew 2013 Locations Crew Land Crew 1-6, 4.0 mmcf/d A1-6, 5.2 mmcf/d (2 months) Septimus/Groundbirch Purchase Crew Septimus plant 45 mmcf/d to be expanded to 65 mmcf/d Type Wells and Economics Economics per well Capex ($mm) 4.7 Current reserves (mboe) 595 Port Frac System Reserves (mboe) 856 Current NPV10 ($mm) 3.1 Port Frac System NPV10 ($mm) 7.3 Sproule April 1, 2013 Forecast Months Port Frac System Forecast (4.6 Bcf EUR) P Avg. Booking (3.2 Bcf EUR) 2012 Completions Actuals (6 wells) P Avg. Booking (2.8 Bcf EUR) 12

13 MNTN Above Upper ( ) [TVD] <U> ( ) [TVD] <U> Shoulder ( ) [TVD] <U> MNTN Above Upper ( ) [TVD] <U> ( ) [TVD] <U> Shoulder ( ) [TVD] <U> C:\Users\JBATCH ~1\AppData\Local\Temp\_$ALOG$_.xsc Page 1 of 2 ( Row 1 C ol A ) Copyright 2012, IHS [AccuLogs, v ] Jan 08, :41:59 Projection: None. Fixed spacing: 1.00 inch Datum: NAD / W6/0 Septimus Core Development KB: m RR: TD: m [TVD] FormTD: MNTN Mode: Susp Fluid: Gas CNRL SEPTIMUS A ( ) BRPLG 1975 ( ) A 2000 ( ) Diamond JET Diamond FRAC 2025 ( ) JET FRAC Diamond B Upper Montney (133M) 2050 ( ) 2075 ( ) C 2100 ( ) Lower Montney Non Producing Locations Zone Booked Unbooked Total 2P Reserves assigned (Bcf) Unbooked Potential Upside (Bcf)* Montney A Montney B Montney A Booked Montney B Booked Montney C Booked Montney A Unbooked Montney B Unbooked Montney C Unbooked Crew Land Montney C TOTAL Grand Total *Unbooked potential upside based on YE 2012 average sales bookings per well (3.2 Bcf) 13

14 Groundbirch Talisman Hz License IP 1.7 mmcf/d IP 1.2 mmcf/d IP 0.8 mmcf/d Shell Hz Standing IP 1.3 mmcf/d Aduro Hz Licenses Strong vertical Montney producers in the immediate area Excellent horizontal producers immediately offsetting lands Moderate - highly over pressured (14 kpa/m) Wet 25 bbls/mmcf (60% cond.) Average 1,850 m depth Upper Montney thickness up to 150 m Shell Hz License Shell pad Crew New HZ Locations TCPL Conceptual Pipeline Route Crew Land IP 5.1 mmcf/d Septimus/Groundbirch Purchase IP 5.7 mmcf/d Shell Hz Standing 14

15 MNTN ( ) [TVD] <U> Shoulde r ( ) [TVD] <U> ACIDSQ FRAC JET 1850 ( ) 1875 ( ) 1900 ( ) 1925 ( ) 1950 ( ) 1975 ( ) 2000 ( ) 2025 ( ) 2050 ( ) 2075 ( ) MNTN ( ) [TVD] <U> Shoulde r ( ) [TVD] <U> Tower, Emerging Montney Oil Play 00/ W6/0 KB: m RR: TD: m [TVD] FormTD: GOLT Mode: Stand Fluid: N/A CREW TOWER Tower, Multi Zone Oil Discoveries 6 month rate 99 bbls/d of 50 API cond, 0.6 mmcf/d Crew 13-8 (33%WI) 23 day test Gross final: 342 bbls/d of oil, 1.7 mmcf/d gas 13-8 Oil Discovery Arc pad development 1-7, Vt test 49 API oil OIL WINDOW Upper Montney (95 m) Crew 1-24 Hz location Crew 1-31 (33% WI) Gross Final: 375 bbls/d of oil, 0.75 mmcf/d gas 1-7 Oil Discovery Lower Montney Crew Septimus facility 5-18, 6 day test, 320 bbls/d oil, 974 mcf/d gas 1-13, 8 day test, 575 bbls/d oil, 1,875 mcf/d gas 8-15, 9 day test, 195 bbls/d oil, 380 mcf/d gas A8-15, 9 day test, 230 bbls/d oil, 215 mcf/d gas B8-15, 10 day test, 595 bbls/d oil, 685 mcf/d gas Crew Oil Wells Crew Licenses Hz Drilling Activity Crew Lands 15

16 Daily Gas Rate (mcfd) Greater Wapiti, Liquids Rich Gas Elmworth 180 Cardium locations 90 bbls/mmcf liquids rich gas 5 Falher locations 00/ W6/0 Prod to date = 560 mmcf Current prod = 209 mcf/d Cardium Type Log Wapiti Cardium Oil Fairway Kakwa Deep Basin - Cardium Horizontal Type Curves Capex/well ($mm) P Deep Basin Reserves (mboe) 460 Kakwa Propane Frac Type Curve (mboe) P Deep Basin NPV10 ($mm) 1.7 Kakwa Propane Frac NPV10 ($mm) 2.6 Sproule April 1, 2013 Forecast 1000 Crew 2013 Locations Crew Wells Thick Cardium Gas Fairway Thick Cardium Oil Fairway Crew Land Month of Production Elmworth Type Curve (9 wells) Kakwa Type Curve (3 wells) P Deep Basin Avg. Booking P Deep Basin Avg. Booking 16

17 10% Discount Lloydminster, Heavy Oil Play CREW 02/ W4 CLNY UMCL Colony 105 bbls/d Crew 100% W.I. Dulwich Heavy Oil facility Forestbank Low Lake Q4/2013 Waterflood Lloydminster Lashburn West Golden Lake SPRK Coal Unwin/Epping GP GP 02/9-30 HZ 96 bbls/d Neilburg Lloydminster Heavy Oil Economics Completions 2 Completions Completion Oil Reserves (mmbl) 4.3 PIR Profit to Investment Ratio (PV10/well cost) Economics based on $60/bbl Heavy Oil Price 5.2 Costs ($M) 560 Reserves/well (mboes) 59 OOIP (mmbbls) 975 Recovery to date (mmbbls) 28.6 (2.9%) 2012 year end booked 2P reserves (mmbbls) drilling locations >400 recompletions Baldwinton Crew Wells Crew Land 17

18 Princess, Alberta Oil Play Battery Inlet 28,000 b/d emulsion Capacity 6,000 bopd 1-24 Battery Inlet 47,000 b/d emulsion Capacity 5,000 bopd N Pool 2013 expansion DD Pool 2013 expansion CC Pool GG Pool CCC Pool K Pool KK Pool K Pool M Pool 7-8 Battery Inlet 65,000 b/d emulsion Capacity 6,500 bopd U Pool HH Pool 8-2 HZ IP2 151 bopd 4-31 VT MNVL IP2 30 bopd (unstimulated) Land Holdings Total (net acres) 315,700 Developed (net) 43,528 Undeveloped (net) 272,172 86% undeveloped Large contiguous land block with excellent economies of scale 11 waterfloods underway 2 waterflood expansions in 2013 (DD & N Pools) Significant exposure to emerging Mannville oil play 36% of Pekisko developed resource is under waterflood 8-8 HZ IP2 375 bopd HZ IP2 360 bopd Analogous Waterfloods 2011 Waterfloods 2012 Waterfloods 2013 Waterfloods Crew Land 18

19 Total Daily Fluid Rate and Avg Daily Injection Rate (bbl/d) & GOR (scf/bbl) Average Daily Oil Volumes (bbl/d) Injected Volume, bbl/d, Produced fluid bbl/d, GOR Oil bbl/d Princess Waterfloods 3000 Bantry Pekisko Bantry HH Pekisko Pool Production HH Pool Graph Princess Pekisko K K Pool Tilley Production Graph Wells down for workover Apr Mar Feb Jan Dec Nov Oct Sept Aug Jul June 2012 May 2012 Apr Mar Feb Jan Dec Nov Oct Sept May 2013 Apr Mar Feb Jan Dec Nov Oct Sept Aug Jul June 2012 May 2012 Apr Mar Feb Jan Daily Fluid (bbl/d) GOR (scf/bbl) Water Injection Rate (bbl/d) Daily Oil (bbl/d) Daily Fluid (bbl/d) GOR scf/bbl Water Injection Rate (bbl/d) Daily Oil (bbl/d) Initial Recoverable Booked Waterflood Initiation OOIP Primary TPP Secondary TPP Half Cycle Cost Half Cycle F&D (Mbbl) (Mbbl) (R.F.) (Mbbl) (R.F.) ($M) ($/bbl) Pools (2) 17,708 2, % 3, % 1, Pools (6) 67,285 5, % 14, % 8, Pools (3) 14,898 1, % 2, % 2, Total 99,891 9, % 19, % 12, ** ** Expected Full Cycle F&D for Princess Field Waterflood ~ $5/bbl Sproule 2012 booking 19

20 Investment Attributes World class Montney resource Expanding focus on improving primary and secondary oil recovery Well positioned to take advantage of new and evolving technologies Uniquely leveraged to narrowing differentials and improving gas prices Established successful record of per share growth Attractive valuation 20

21 APPENDIX RESOURCE FOCUS OPPORTUNITY SUSTAINABILITY 21

22 Reserve Summary % Proved plus probable (mmboe) % Per share (mboe/mmshares) 1,258 1,144 10% Proved (mmboe) % Per share (mboe/mmshares) % Reserve value 10% discount (2P - $mm) $1,478 $1,642 (10%) Finding, development and acquisitions costs (2P$/boe) $8.17 $18.37 (56%) Finding and development (2P$/boe) $11.71 $17.88 (35%) Recycle ratio F,D & A 2P 2.7x 1.4x 93% Net asset value per share (10% discount) $11.98 $13.41 (11%) 22

23 2012 Financial Review P&NG sales (000 s) $417,763 $388,166 Cash flow (000 s) $186,604 $172,103 Cash flow per diluted share $1.54 $1.67 Earnings (000 s) $21,542 ($130,162) Earnings per share $0.18 ($1.28) Net Debt (000 s) $291,356 $323,128 Production (boe/d) 27,963 22,452 % Liquids 52% 49% Average price per boe $43.14 $47.64 Cash cost per boe $21.79 $24.03 Operating net back $21.35 $

24 Cash Flow Sensitivity Natural Gas Price (AECO C$/mcf) ($mm) $2.75 $3.25 $3.50 $3.75 $ % WTI to WCS 30% Differential 25% % % Note: Includes Q actual WTI is held constant at the base budget level of C$94/bbl for Q2 to Q

25 N.E.B.C. Montney Resource Evaluation Natural Gas Resource Categories (1)(2)(3) Total Petroleum Initially In Place (TPIIP) Discovered Petroleum Initially In Place (DPIIP) Undiscovered Petroleum Initially In Place (UPIIP) (1) All volumes in table are company gross and raw gas volumes. (2) Sproule s analysis identified four intervals in the Montney consisting of one interval in the Upper Montney and three intervals in the Lower Montney. (3) Crew s acreage was divided into six (6) areas in the gas window. Crew owns 192 net sections in the gas window at May 1, Oil Resource Categories (1)(2)(3)(4) Total Petroleum Initially In Place (TPIIP) Discovered Petroleum Initially In Place (DPIIP) Undiscovered Petroleum Initially In Place (UPIIP) (1) All volumes in table are company gross. (2) The oil volumes are quoted as Stock Tank Barrels ( STB ). (3) Sproule s analysis identified four intervals in the Montney consisting of one interval in the Upper Montney and three intervals in the Lower Montney. (4) Crew s acreage was divided into five (5) areas in the oil window. Crew owns 100 net sections in the oil window at May 1, Reserves and Contingent Resources (1)(2) Natural Gas (Tcf) Reserves (3) Contingent Resources (6) Natural Gas Liquids (mmbbls) (4)(5) Reserves (3) Contingent Resources (6) Oil (mmbbls) Reserves (3) Contingent Resources (1) All DPIIP other than cumulative production, reserves, and Contingent Resources has been categorized as unrecoverable at this time. (2) All volumes in table are company gross and sales volumes. (3) For reserves, the volume under the heading Best Estimate are proved plus probable reserves as at December 31, (4) The liquid yields are based on average yield over the producing life of the property. (5) Liquid yields are unique to each area. They are estimated based on gas composition of gas samples in the area and expected plant recoveries. (6) Project economic Status is currently undetermined. There is no certainty that it will be commercially viable to produce any of the resources. Prospective Resources (1)(2) Natural gas (Tcf) Natural gas liquids (mmbbls) Oil (mmbbls) (1) All UPIIP other than Prospective Resources has been categorized as unrecoverable at this time. (2) All volumes in table are company gross and sales volumes. Tcf Mmbbls 7, ,151.5 Best Estimate Best Estimate

26 Definitions of Oil and Gas Resources and Reserves Reserves are estimated remaining quantities of oil and natural gas and related substances anticipated to be recoverable from known accumulations, as of a given date, based on the analysis of drilling, geological, geophysical and engineering data; the use of established technology; and specified economic conditions, which are generally accepted as being reasonable. Reserves are classified according to the degree of certainty associated with the estimates as follows: Proved Reserves are those reserves that can be estimated with a high degree of certainty to be recoverable. It is likely that the actual remaining quantities recovered will exceed the estimated proved reserves. Probable Reserves are those additional reserves that are less certain to be recovered than proved reserves. It is equally likely that the actual remaining quantities recovered will be greater or less than the sum of the estimated proved plus probable reserves. Possible Reserves are those additional reserves that are less certain to be recovered than probable reserves. It is unlikely that the actual remaining quantities recovered will exceed the sum of the estimated proved plus probable plus possible reserves. Cumulative Production is the cumulative quantity of petroleum that has been recovered at a given date. Resources encompasses all petroleum quantities that originally existed on or within the earth's crust in naturally occurring accumulations, including Discovered and Undiscovered (recoverable and unrecoverable) plus quantities already produced. "Total resources" is equivalent to "Total Petroleum Initially-In-Place". Resources are classified in the following categories: Total Petroleum Initially-In-Place ("TPIIP") is that quantity of petroleum that is estimated to exist originally in naturally occurring accumulations. It includes that quantity of petroleum that is estimated, as of a given date, to be contained in known accumulations, prior to production, plus those estimated quantities in accumulations yet to be discovered. Discovered Petroleum Initially-In-Place ("DPIIP") is that quantity of petroleum that is estimated, as of a given date, to be contained in known accumulations prior to production. The recoverable portion of discovered petroleum initially in place includes production, reserves, and contingent resources; the remainder is unrecoverable. Contingent Resources are those quantities of petroleum estimated, as of a given date, to be potentially recoverable from known accumulations using established technology or technology under development but which are not currently considered to be commercially recoverable due to one or more contingencies. Contingences may include such factors 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. Undiscovered Petroleum Initially-In-Place ("UPIIP") is that quantity of petroleum that is estimated, on a given date, to be contained in accumulations yet to be discovered. The recoverable portion of undiscovered petroleum initially in place is referred to as "prospective resources" and the remainder as "unrecoverable." Prospective Resources are those quantities of petroleum estimated, as of a given date, to be potentially recoverable from undiscovered accumulations by application of future development projects. Prospective resources have both an associated chance of discovery and a chance of development. Unrecoverable is that portion of DPIIP and UPIIP quantities which is estimated, as of a given date, not to be recoverable by future development projects. A portion of these quantities may become recoverable in the future as commercial circumstances change or technological developments occur; the remaining portion may never be recovered due to the physical/chemical constraints represented by subsurface interaction of fluids and reservoir rocks. Uncertainty Ranges are described by the Canadian Oil and Gas Evaluation Handbook as low, best, and high estimates for reserves and resources. The Best Estimate is considered to be the best estimate of the quantity that will actually be recovered. It is equally likely that the actual remaining quantities recovered will be greater or less than the best estimate. 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. 26

27 Information on Reserves, Resources and Operational Information All amounts in this presentation are stated in Canadian dollars unless otherwise specified. Throughout this presentation, the terms Boe (barrels of oil equivalent), Mmboe (millions of barrels of oil equivalent), and Tcfe (trillion cubic feet of gas equivalent) are used. Such terms when used in isolation, may be misleading. Where applicable, natural gas has been converted to barrels of oil equivalent ("BOE") based on 6 Mcf:1 BOE and oil and liquids have been converted to natural gas equivalent on the basis of 1 bbl:6 mcfe. The BOE rate is based on an energy equivalent conversion method primarily applicable at the burner tip, and given that the value ratio based on the current price of crude oil as compared to natural gas is significantly different than the energy equivalency of the 6:1 conversion ratio, utilizing the 6:1 conversion ratio may be misleading as an indication of value. The BOE rate is based on an energy equivalent conversion method primarily applicable at the burner tip and does not represent a value equivalent at the wellhead. In accordance with Canadian practice, production volumes and revenues are reported on a company gross basis, before deduction of Crown and other royalties, unless otherwise stated. Unless otherwise specified, all reserves volumes in this presentation (and all information derived therefrom) are based on "company gross reserves" using forecast prices and costs. Our oil and gas reserves statement for the year-ended December 31, 2012 includes complete disclosure of our oil and gas reserves and other oil and gas information in accordance with NI , and is contained within our Annual Information Form which is available on our SEDAR profile at The resource estimates contained herein are based upon an independent evaluation of Crew s Montney lands in North East British Columbia prepared by Sproule Associates Limited effective May 1, 2013 in accordance with the COGE handbook. This presentation contains references to estimates of oil and gas classified as TPIIP and DPIIP in the Montney region in northeastern British Columbia which are not, and should not be confused with, oil and gas reserves. See "Definitions of Oil and Gas Resources and Reserves". TPIIP, DPIIP and UPIIP have been estimated using a zero percent porosity cutoff. Projects have not been defined to develop the resources in the Evaluated Areas as at the evaluation date. Such projects, in the case of the Montney resource development, have historically been developed sequentially over a number of drilling seasons and are subject to annual budget constraints, Crew's policy of orderly development on a staged basis, the timing of the growth of third party infrastructure, the short and long-term view of Crew on gas prices, the results of exploration and development activities of Crew and others in the area and possible infrastructure capacity constraints. As with any resource estimates, the evaluation will change over time as new information becomes available. The Prospective Resource have not been risked for chance of discovery. There is no certainty that any portion of the Prospective Resources will be discovered. The Prospective and Contingent Resources have not been risked for chance of development. There is no certainty that it will be commercially viable to produce any portion of the Prospective (if discovered) or Contingent Resources. The Contingent Resource contingencies are identified as economic or non-technical, there are no technical contingencies. Significant positive factors are historic drilling success and production history on the more fully developed Montney acreage, abundant well log and production test data. Potential negative factors include lack of long term production history over the majority of Crew lands, lack of infrastructure, potential for variations in the quality of the Montney formation where minimal well data currently exists, access to the substantial amount of capital which would be required to develop the resources, low commodity prices that would curtail the economics of development and the future performance of wells, regulatory approvals, access to the required services at the appropriate cost and topographic or surface restrictions. Crew's belief that it will establish significant additional reserves over time with the conversion of Prospective Resource into Contingent Resource, Contingent Resource into probable reserves and probable reserves into proved reserves is a forward looking statement and is based on certain assumptions and is subject to certain risks, as discussed at the beginning of this presentation in the slide titled Cautionary Statement. 27

28 Corporate Information TSX Trading symbol CR Basic shares (mm) Market $6.00/sh (mm) $ Average trading volume per day (m) 961 Employee/Director ownership diluted 6% 28

29 CONTACT INFORMATION Dale O. Shwed, President & CEO (403) John G. Leach, Senior Vice President & CFO (403) Rob J. Morgan, Senior Vice President & COO (403) RESOURCE FOCUS OPPORTUNITY SUSTAINABILITY 29