BUILDING OUR FUTURE IN THE MONTNEY

Transcription

1 BUILDING OUR FUTURE IN THE MONTNEY

2 CAUTIONARY STATEMENT Forward Looking Statements 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, forecast and similar expressions are intended to identify forward-looking information or statements. In particular, but without limiting the forgoing, this presentation contains forwardlooking 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 northeast British Columbia ( NEBC ); the volume and product mix of Crew's oil and gas production; production estimates including 2017 forecast average and exit productions and production per share growth; the recognition of significant resources in the Montney region of NEBC; 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; forecast 2017 net debt; forecast 2017 cash flow and year end bank debt; future costs, expenses and royalty rates; future interest costs; the exchange rate between the $US and $Cdn; future development, exploration, acquisition and development activities, infrastructure build out and related capital expenditures and the timing thereof; the amount and timing of capital projects; operating costs; the total future capital associated with development of reserves and resources; methods of funding our capital program including possible non-core asset divestitures; and forecast reductions in well costs and operating expenses. In this presentation reference is made to the Company's long range Montney growth scenario and economic analysis. All information derived therefrom are not estimates or forecasts of metrics that may actually be achieved. Such information reflects internal projections used by management for the purposes of making capital investment decisions and for internal long range planning and budget preparation. Accordingly, undue reliance should not be placed on same. 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. There are a number of assumptions associated with the potential of resource volumes assigned to lands evaluated in Crew's Montney area of operations in NEBC, including the quality of the Montney reservoir, future drilling programs and the funding thereof, continued performance from existing wells and performance of new wells, the growth of infrastructure, well density per section and recovery factors and discovery and development of the lands evaluated in Crew's Montney area of operations in NEBC necessarily involves known and unknown risks and uncertainties, including those identified in this presentation and including the business risks discussed in Crew's annual and quarterly MD&A and other continuous disclosure documents. Crew s 2017 budget guidance and related targets and forecasts disclosed herein are best estimates based on certain assumptions including, without limitation, operating results, known fiscal regimes, commodity prices and risk management contracts and will be regularly monitored by management. Our objective will be to proactively manage our capital program as it relates to operational success and fluctuating commodity prices with a priority to maintain financial flexibility and achieve our production guidance. Crew will closely monitor the budget and financial situation throughout the year to assess market conditions and will quickly adjust budget levels or pace of development in accordance with commodity prices and available funds from operations. 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; the potential for variation in the quality of the Montney formation; 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 forwardlooking statements or information, whether as a result of new information, future events or otherwise, except as may be required by applicable securities laws. 2

3 BUILDING OUR FUTURE IN THE MONTNEY 18+billion BOE of TPIIP Resource +20% 1P reserves per share growth in 16 over 15 ~5,400 Identified drilling locations (1) FINANCIAL DISCIPLINE ~71% Condensate as a percentage of forecast liquids production in ,000 Net acres in the Montney 275+mmcf/d Long-term takeaway capacity to diverse markets +17% production per share growth in 16 over 15 PEOPLE ASSETS TECHNOLOGY 3 (1) Identified locations are the total number of risked Contingent (2,056) and Prospective (3,377) resource locations as identified in Crew s annual year end independent resource evaluation prepared in accordance with the COGE Handbook provisions and NI See complete details on the resource evaluation in presentation appendix.

4 ABOUT CREW (TSX: CR) Growth-oriented Montney producer with large, contiguous land base in NE BC Track Record of Successful Montney Execution Access to diversified markets with operated infrastructure and increasing liquids production leads to top quartile netbacks 25,000 20,000 Montney Production (2) (BOE/D) Light oil bopd NGLs boepd Gas boepd Forecast >30,000 boe/d forecast 2017 exit production (25,000-27,000 boe/d forecast annual average) 15,000 10,000 $535MM of total debt capacity ($300MM senior notes and $235MM credit facility currently undrawn) ~$725MM market cap (146.8MM shares O/S) 4 48% hedged On forecast 2017 gas sales at $3.62/mcf (1) 43% hedged On forecast 2017 light oil & ngl sales at $68.17/bbl (1) Adjusted to reflect Crew s average natural gas heat content 1.24 GJ / mcf (2) Reflects production from Greater Septimus and Tower (Tower is included as Other in financial statement disclosure) (3) Based on Crew s annual year end independent reserves evaluations. 5, P+P Reserves (MMBOE) (3) Liquids mmbbls Gas mboe

5 CNQ ARX CR ECA KEL Shell PPY TOU SU LXE Repsol PWT MASSIVE LAND POSITION IN THE SWEET SPOT OF THE MONTNEY Only 14% of Crew s 474 net sections have Upper Montney reserves assigned 3rd Largest BC Montney landholder among public companies Net Acres of Montney Rights in NE BC (000 s) Net Sections 266 Wet Gas Sections 141 Oil/Condensate Sections 67 Dry Gas Sections Crew Energy Inc. Arc Resources Broker Lands Canadian Natural Res. Encana Kelt Exploration Leucrotta Exploration Painted Pony Petroleum Penn West Petroleum Repsol Shell Canada Suncor Energy Source: RBC Capital Markets. Tourmaline Oil Source: Peters & Co, Company Reports.

6 RISING NETBACKS & LOWER COSTS High Quality Montney Assets Support Strong Q Results Top Quartile Operating Netbacks (Pre-Hedging) Among Montney-Focused Peers ($/boe) Top Quartile Montney Operating Costs Among Montney-Focused Peers ($/boe) $22 $11 $20 $18 $16 $18.61 $17.38 Group Average = $16.14 $10 $9 $8 $14 $12 $7 $6 $5.35 Group Average = $6.15 $10 $5 $8 $4 $3.34 $6 $3 $4 $2 $2 $1 $0 1 2 CR CR Corp Montney $ CR Corp CR Montney Source: NBF, Public Filings. Companies included in above analysis include VII, NVA, TET, PEY, POU, BIR, KEL, AAV, DEE, PPY, SRX, CQE

7 CONTINUAL IMPROVEMENTS IN CAPITAL EFFICIENCIES Drilling Days On-stream Costs - 90 Day Average IP ($ per boe/d) Declining Drilling Days Reduces Costs $18,000 $16,000 $14,000 Enhanced completions + lower costs = Improving efficiencies % Improvement $12,000 $10, $8,000 $6,000 81% Improvement 10 $4,000 5 $2,000 $ Q wells Q wells Q wells Q wells Q wells Q wells Q wells Q wells 0 Pad 14-7 Pad 4-24 Pad Pad 8-22 Pad 9-17 Pad Pad 7-30 Pad 5-24 Pad 4-34 Pad 5-7 Pad Key service costs locked-in through 2017 support continued activity Improved drilling efficiency is a structural change

8 Lower Montney 1,000 Feet Upper Montney CREW MONTNEY STRATIGRAPHIC STACK 2 HZ Wells 3 HZ Wells 3 HZ Wells 54 HZ Wells 77 HZ Wells 1 HZ Well 10 HZ Wells West Portage Groundbirch Attachie West Septimus Septimus Goose Tower Doig 2 1 AA A B C 2 3 Monias High Crew HZ wells drilled to Q1, 2017 Belloy 8 Crew recognizes four major clinoform units in the Upper Montney (AA, A, B, C) The majority of Crew horizontals (70%) have been drilled in the B clinoform The Lower B and C clinoforms are still essentially undrilled The Lower Montney unit also has excellent prospectivity, especially at Septimus, Tower and Attachie

9 Daily Gas Production (mcfd) 9 WEST SEPTIMUS Economics (1) : Full Cycle Half Cycle Capital Expenditures ($MM) $4.3 $3.5 1 Month IP (boe/d) 1,029 1,029 Oil (mbbls) 0 0 NGLs (mbbls) Sales Gas (bcf) (raw: 4.5 bcf) Total Reserves (mboe) NPV10 ($MM) $3.7 $4.5 PIR (10% discount) ROR Before Tax (%) 64% 112% F&D ($/boe) $4.39 $3.57 Payout (years) (1) Economic Assumptions: Based on Sproule s year end P type wells for West Septimus; Dec. 31, 2016 forward price deck as follows: Cal 17: C$3.32/GJ AECO; US$56.40 WTI, $074 F/X; Cal 18: C$2.86/GJ AECO, US$56.54 WTI, $0.75 F/X; Cal 19: C$2.55/GJ AECO, US$56.08 WTI, $0.75 F/X; Cal 20: C$2.55/GJ AECO, US$56.00 WTI, $0.76 F/X; Cal 21 and thereafter: C$2.55/GJ AECO, US$56.13 WTI, $0.76 F/X. (2) Identified locations are the total number of risked Economic Contingent, development pending and development on hold subcategories as identified in Crew s annual year end independent resource evaluation prepared in accordance with the COGE Handbook provisions and NI See complete details on the resource evaluation in presentation appendix. 512 Identified Locations (2) 9,000 8,000 7,000 6,000 5,000 4,000 3,000 2,000 1,000 Outperformance of Initial West Septimus Type Curve (4)(5) Time (days) Pad (6 wells in Q2/15) 9-17 Pad (5 wells in Q4/15 & Q2/16) 4-24 North Pad (3 wells in Q1&Q2 2015) 4-24 South (6 wells in Q1/15) 8-22 Pad (3 wells in Q1/16) pad (4 wells in Q2&Q3/16) Sproule 2014 type curve (3.2 bcf) Sproule 2015 type 2P type curve curve (4.5 (4.5 bcf) bcf) (3) Based on initial production data from Crew s W6 well. (4) See the Appendix to this presentation for information on Type Wells. (5) Sproule s 2015 vs 2014 figures represent average EUR per well for undeveloped locations assigned by Sproule in Crew s annual year end reserves reports. Condensate -Rich Up to 220 bbl/mmcf (3)

10 $MM SEPTIMUS: FREE CASH FLOW GENERATION Economics (1) : Full Cycle Half Cycle Capital Expenditures ($MM) $4.3 $3.5 1 Month IP (boe/d) Oil (mbbls) 0 0 NGLs (mbbls) $100 $ Identified Locations (2) ~$108 MM Free cash flow generated (3) Free cash flow directed to fund continued Montney growth 10 Sales Gas (bcf) (raw: 5.6 bcf) Total Reserves (mboe) 1,037 1,037 NPV10 ($MM) $3.2 $4.0 PIR (10% discount) ROR Before Tax (%) 49% 83% F&D ($/boe) $4.15 $3.38 Payout (years) (1) Economic Assumptions: Based on Sproule s year end P type wells for Septimus; Dec. 31, 2016 forward price deck as follows: Cal 17: C$3.32/GJ AECO; US$56.40 WTI, $074 F/X; Cal 18: C$2.86/GJ AECO, US$56.54 WTI, $0.75 F/X; Cal 19: C$2.55/GJ AECO, US$56.08 WTI, $0.75 F/X; Cal 20: C$2.55/GJ AECO, US$56.00 WTI, $0.76 F/X; Cal 21 and thereafter: C$2.55/GJ AECO, US$56.13 WTI, $0.76 F/X. (2) Identified locations are the total number of risked Economic Contingent, development pending and development on hold subcategories as identified in Crew s annual year end independent resource evaluation prepared in accordance with the COGE Handbook provisions and NI See complete details on the resource evaluation in presentation appendix. $60 $40 $20 $ (3) Forecast Cash Flow Capex (3) Cash Flow Assumptions for Forecast: Cal 17: C$3.13/GJ AECO, US$3.50 NYMEX; US$54.25 WTI, $076 F/X; Cal 18: C$2.85/GJ AECO, US$3.05 NYMEX, US$55.00 WTI, $0.75 F/X; Cal 19: C$2.75/GJ AECO, US$2.90 NYMEX, US$55.00 WTI, $0.75 F/X.

11 ULTRA CONDENSATE-RICH AREA IS NEW FOCUS AT GREATER SEPTIMUS Economics (1) : Half Cycle Ultra Condensate-Rich Capital Expenditures ($MM) $4.3 1 Month IP (boe/d) 1,064 Condensate (mbbls) 243 NGLs (mbbls) 61 Sales Gas (bcf) 3.5 Total Reserves (mboe) 892 Crew 4-22 Pad Drilling Operations C7-30: 60,000 bbls condensate in 180 days, avg CGR of 188 Crew 7-30 Pad Crew Pad B7-30: 35,000 bbls condensate in 125 days; avg CGR of NPV10 ($MM) 6.0 PIR (10% discount) 1.5 ROR Before Tax (%) 157 F&D ($/boe) 4.82 Payout (years) 0.8 (1) Economic Assumptions: Based on Sproule s year end P type wells for Tower; Dec. 31, 2016 forward price deck as follows: Cal 17: C$3.32/GJ AECO; US$56.40 WTI, $074 F/X; Cal 18: C$2.86/GJ AECO, US$56.54 WTI, $0.75 F/X; Cal 19: C$2.55/GJ AECO, US$56.08 WTI, $0.75 F/X; Cal 20: C$2.55/GJ AECO, US$56.00 WTI, $0.76 F/X; Cal 21 and thereafter: C$2.55/GJ AECO, US$56.13 WTI, $0.76 F/X. Crew 15-9 Pad Drilling Operations Montney 2017 Drilling Locations Montney A Drilled Wells Montney B Drilled Wells Montney Lower B Drilled Wells Montney C Drilled Wells Lower Montney Drilled Wells Crew Montney Acreage Ultra Condensate Rich Area (2) Identified locations are the total number of risked Economic Contingent, development pending and development on hold subcategories as identified in Crew s annual year end independent resource evaluation prepared in accordance with the COGE Handbook provisions and NI See complete details on the resource evaluation in presentation appendix. W. Septimus Facility 60 mmcf/d Capacity Expanding to 120 mmcf/d >165 potential drill locations (2) Estimated in ultra condensate-rich area, up to 1/3 of W. Septimus locations

12 TOWER OIL Economics (1) : High -Netback Light, sweet oil Full Cycle Half Cycle Capital Expenditures ($MM) $6.1 $5.2 Crew Month IP (boe/d) Oil (mbbls) NGLs (mbbls) Sales Gas (bcf) Total Reserves (mboe) NPV10 ($MM) $0.01 $0.95 PIR (10% discount) Crew 9-30 Crew Oil Battery 12 ROR Before Tax (%) 11% 20% F&D ($/boe) $15.64 $13.33 Payout (years) (1) Economic Assumptions: Based on Sproule s year end P type wells for Tower; Dec. 31, 2016 forward price deck as follows: Cal 17: C$3.32/GJ AECO; US$56.40 WTI, $074 F/X; Cal 18: C$2.86/GJ AECO, US$56.54 WTI, $0.75 F/X; Cal 19: C$2.55/GJ AECO, US$56.08 WTI, $0.75 F/X; Cal 20: C$2.55/GJ AECO, US$56.00 WTI, $0.76 F/X; Cal 21 and thereafter: C$2.55/GJ AECO, US$56.13 WTI, $0.76 F/X. 127 Identified Locations (2) Montney 2017 Drilling Locations Montney Future Locations Montney B Drilled Wells Montney C Drilled Wells Montney Oil Line Crew Pipelines Crew Montney Acreage (2) Identified locations are the total number of risked Economic Contingent, development pending and development on hold subcategories as identified in Crew s annual year end independent resource evaluation prepared in accordance with the COGE Handbook provisions and NI See complete details on the resource evaluation in presentation appendix.

13 Gas production (mcf/d) FUTURE GROWTH OPPORTUNITIES Over-pressured, liquids-rich natural gas areas ATTACHIE 1,000 thick pay (Upper + Lower Montney) Several prolific offsetting producers in Upper & Lower Montney ~97 net sections 90+ Wells 3 Lower Montney Zones Attachie Greater Septimus Lower Montney identified 90+ locations at Greater Septimus (1) LOWER MONTNEY Multiple prospective zones Successful pilot wells prove resource with several prolific offsetting producers in the Lower Montney Crew Lower Montney production exceeding 5.6 Bcf type curve (see below) Avg. Daily Rate 6,000 5,000 Crew Septimus Sproule 5.6 Bcf Type Curve GROUNDBIRCH Expected development of wells per section in Upper Montney Ideally situated for proposed N. Montney Mainline access Planned Groundbirch 120 mmcf/d Plant ~156 net sections Groundbirch 100+ Wells 1 Lower Montney Zone 4,000 3,000 2,000 1, Time (months) 13 (1) Identified locations are the total number of risked Economic Contingent, development pending and development on hold subcategories as identified in Crew s annual year end independent resource evaluation prepared in accordance with the COGE Handbook provisions and NI See complete details on the resource evaluation in presentation appendix.

14 FIRM SERVICE ARRANGEMENTS & STAGED PROCESSING SUPPORT GROWTH PLAN 400,000 Transportation TCPL/Nova: 60 mmcf/d firm increasing to 120 mmcf/d (Jun 19) Spectra: 13 mmcf/d firm increasing to 30 mmcf/d (Apr 17) Alliance: 100 mmcf/d firm (+ 25 priority interruptible available) Processing Groundbirch: 120 mmcf/d (Q4 18) W. Septimus: 60 mmcf/d expanding to 120 mmcf/d (Q4 17) Septimus: 60 mmcf/d 300,000 Numbers above do not include access to interruptible or shorter term transportation opportunities Additional capacity post-2020 is available on the TCPL / Nova System * * 200, , Jan-17 Jul-17 Jan-18 Jul-18 Jan-19 Jul-19 Jan-20

15 SECURED LONG TERM TRANSPORTATION Long-term transportation capacity and market planning facilitates growth to ~60,000 boe/d to 2019 Three pipeline options running west, east and south provide access to North American markets Diversified gas marketing strategy offers exposure to Chicago City Gate, AECO, ATP, Station II & Sumas markets Portage Attachie Goose West Septimus Flatrock Alliance Pipeline 1.6 Bcf/d 15 Minimum of 2,200 bbls/d Condensate and light oil with long-term transportation capacity secured Minimum of 275 mmcf/d Long-term takeaway capacity with operational & market diversification Spectra T-North Ft. Nelson Mainline 1.4 Bcf/d TCPL N. Montney Project 2.4 Bcf/d Groundbirch Spectra T-North Ft. St. John Mainline 0.7 Bcf/d (current) 0.85 Bcf/d (post expansion) Septimus Crew Operated Pipeline Crew 2017/2018 Pipeline Construction Alliance Operated Pipeline Spectra Westcoast Operated Pipelines Pembina Peace Condensate Pipeline TCPL Operated Pipeline Proposed TCPL North Montney Mainline Project Tower Crew Operated Gas Plant Crew Planned Gas Plant Spectra McMahon Gas Plant TCPL Saturn Meter Station Crew Montney Acreage

16 Natural Gas Prices ($C/MCF) ADVANTAGES OF GAS MARKET DIVERSITY $3.50 $3.00 Commencement of Alliance Pipeline service and initiation of diversified contract portfolio $2.50 $2.00 $1.50 $1.00 $0.50 $ - Enhancedgas price Enriched by heat content + diversified portfolio Crew s Gas Market Diversity Q1, 2017 Nov-15 Dec-15 Q Q Q Q ATP 17% AECO 5A Stn 2 12% 26% 45% Chicago City Gate 16 (1) Crew Realized Price Chicago City Gate at ATP AECO 5A ATP (CREC) Stn #2 (1) Wellhead price before impact of hedging.

17 BUILDING OUR MONTNEY FUTURE 17% Production / Sh Growth 2016 over 2015 Financial Discipline 0% drawn on $235MM facility 17 Massive Resource 18 billion+ boe TPIIP Access to Infrastructure Existing and growing Per Share Reserves Growth 20% increase in 1P reserves/share in 2016 (1) Increasing Liquids Focus on ultra condensate-rich development (1) Compared to 2015.

18 Contact Info: Suite 800, 250-5th Street SW Calgary, Alberta T2P 0R4 Telephone: (403) Dale O. Shwed, President & CEO John G. Leach, Senior Vice President & CFO Robert J. Morgan, Senior Vice President & COO 18

19 Appendix

20 CAPITAL STRUCTURE MARKET SUMMARY (TSX: CR) as at Apr Basic shares outstanding (mm) Trading range (52 week) $ $8.10 Average daily trading volume (m) 909 Market $4.97 / sh (mm) $725 Enterprise value (mm) $1,025 Insider ownership diluted 6.3% DEBT SUMMARY (mm) YE 2016 bank debt drawn on $235mm facility $ % high yield notes (redeemed Mar. 2017) $147.3 YE 2016 net debt (includes working capital deficiency) $245.4 NEW 6.5% high yield notes (maturing Mar. 2024) $300 Post-refinancing total debt capacity ($235 facility + $300 new notes) $535 Forecast YE 2017 net debt following refinancing $ $235 MM Of liquidity on $235MM credit facility (0% drawn)

21 2017 CAPITAL PROGRAM AND FORECAST 2017 Cash Flow (CF) (mm) $149 Capex (mm) $200 Year-end net debt (mm) $309 Debt to annualized Q4 CF 1.6x Assumptions: Production guidance (boepd) 25,000 to 27,000 Pricing Gas (AECO-C$/mcf) $3.24 Oil (WTI-C$/bbl) $72.39 WTI to WCS diff. 30% FX ($US/$CDN) $0.75 Interest rate-bank debt 4.7% Interest rate-high yield 6.5% Royalties 7% Op. costs ($/boe) $ Transportation ($/boe) $ G&A ($/boe) $ Interest Expense ($/boe) $ Hedging Summary as of April 1, 2017 Volume Period Derivative Reference Price Natural Gas 35,000 GJ/Day 2017 Swap AECO $2.89/GJ 27,500 mmbtu/day 2017 Swap Chicago C$3.95/mmbtu 5,000 GJ/Day 2017 Physical Station 2 C$2.50/GJ 2,500 GJ/Day 2018 Swap AECO C$2.62/GJ 5,000 mmbtu/day 2018 Swap Chicago C$4.23/mmbtu Oil 1,000 bopd Feb June 2017 Swap $C WTI / bbl C$ ,750 bopd Jan Dec 2017 Swap $C WTI / bbl C$ bopd Feb June 2017 Swap $C WCS-WTI / bbl (C$19.40) 21

22 SUMMARY OF NEW TERM DEBT Issuer: Crew Energy Inc. (the Company ) Issue: $300 million senior unsecured notes (the Notes ) Coupon: 6.5% Issue Ratings: DBRS: B S&P: B Term: Seven years (7NC3) Ranking: Senior unsecured ranking pari passu with all existing and future senior unsecured indebtedness Use of Proceeds: The Company plans to use the net proceeds from the sale of the Notes for the redemption of the 2020 Notes, for a non-permanent repayment of existing indebtedness under its credit facility, and for general corporate purposes Optional Redemption: The Company may, at its option, redeem all or part of the Notes at any time prior to March 14 th, 2020 at the make whole price and on or after March 14 th, 2020, at the agreed upon redemption prices Equity Clawback: Within the first three years, up to 35% of the issue may be redeemed at a premium of par plus the coupon with the proceeds of an equity offering Change of Control: Offer to repurchase at 101% Covenants: Substantially the same as the Company's existing notes 22

23 DRIVING DOWN COSTS THROUGH ENHANCED OPERATING + CORPORATE EFFICIENCIES % Reduction in cash costs / boe from Q4 14 to Q Enhanced operational efficiencies and increased volumes from Greater Septimus have contributed to continued improvements Q Q Q Q Q Q Q Q Q OPEX G&A Transportation Interest

24 24 WEST SEPTIMUS FOCUS IN 2017 BUDGET DRIVES MONTNEY PRODUCTION AND INFRASTRUCTURE GROWTH Overview Target exit production of 30,000+ boe/d with annual volumes of 25-27,000 boe/d (28% liquids) ~15% growth in average volumes 2017 over well program with 3 drilling rigs running through 1H 2017 & service costs negotiated through end of 2017 Complete and tie-in 11 wells previously drilled in 2016 to support production growth West Septimus Drill & complete 23 (21.3 net) total cost of ~$3.8 MM / well (DCE&T) & complete additional 5 net wells Double capacity of W. Septimus facility to 120 mmcf/d on-stream Q & begin tie-in of W. Septimus infrastructure into TCPL Saturn meter station (in service early 2018) Septimus Drill & complete 1 net ~$3.6 MM / well cost (DCE&T) & complete 4 wells drilled in 2016 Expand pipeline to accommodate volumes from W. Septimus expansion & de-bottlenecking projects at Septimus Tower Complete 2 remaining wells from 2014 drilling program & drill 4 new ~$5.4 MM / well cost (DCE&T)

25 $200MM 2017 BUDGET & GROWTH OUTLOOK 90% Directed to Montney Production Growth & Infrastructure Expansion $140MM Directed to Montney drill, complete, equip & tie-in activities % Montney growth Q4 16 to Q4 17 exit production <1.5x debt / FFO Forecast YE 2017 net debt to Q4 17 annualized funds from operations Montney Capital by Area W. Septimus $127.5MM Tower $29.5MM Septimus $24MM 28,000 21,000 14,000 7,000 - Montney Production (BOE/D) +40% Q4 '15 Q4 '16 Q4 '17

26 $/boe 2016 YEAR END RESERVES HIGHLIGHTS Strong Montney Reserves Growth With Improving Capital Efficiencies Total Reserves (mmboe) 2016 Change (after production) 2016 Change (per share) 2016 Reserves Replacement NPV10 (BT) ($millions) 2P: % 19% 857% 2,012 1P: % 21% 482% 1,011 PDP: % 7% 154% 459 $16 $12 $8 3 Year Average F&D (1)(2)(3) $14.45 $11.08 $9.88 $8.38 $9.15 $7.39 $4 +32% Montney locations 356 2P booked undeveloped future Montney locations $ P F&D 2P F&D 26 (1) All F&D and FD&A figures include change in future development capital. (2) See Appendix for definitions and methodology for calculation of F&D and FD&A. (3) 2016 numbers calculated using unaudited financial and operating information.

27 STABLE ASSET: LLOYDMINSTER HEAVY OIL Lloydminster Currently in sales process 73,326 net acres of land in the area; average WI of 93% 2016 production 2,486 boe/d; Q ,191 boe/d $50MM disposition closed Q capital $7.5MM & forecast annual production of 2,000 boe/d ALBERTA SWIMMING WILDMERE VIKING / KINSELLA Lloydminster LASHBURN UNWIN / EPPING FOREST BANK SASKATCHEWAN BRIGHTSAND LOW LAKE NEILBURG UNITY BALDWINTON Disposition Area Crew 100% W.I. Dulwich Heavy Oil Facility LUSELAND

28 NE BC MONTNEY RESOURCE EVALUATION Dec. 31, 2015 Dec. 31, 2014 Conventional Natural Gas Resource Categories (1)(2)(3)(4) Tcf Tcf % Total Petroleum Initially In Place (TPIIP) Discovered Petroleum Initially In Place (DPIIP) Undiscovered Petroleum Initially In Place (UPIIP) % 15% (14%) (1) TPIIP, DPIIP and UPIIP have been estimated using a one percent porosity cut-off in the 2015 report, which means that essentially all gas bearing rock has been incorporated into the calculations. (2) All volumes in table are Company gross and raw gas volumes.. (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 gas window. Dec. 31, 2015 Dec. 31, 2014 Light & Medium Crude Oil Resource Categories (1)(2)(3)(4)(5) Mmbbls Mmbbls % Total Petroleum Initially In Place (TPIIP) Discovered Petroleum Initially In Place (DPIIP) Undiscovered Petroleum Initially In Place (UPIIP) 7,895 1,613 6,282 7,640 1,501 6,139 (1) TPIIP, DPIIP and UPIIP have been estimated using a one percent porosity cut-off in the 2015 report, which means that essentially all oil bearing rock has been incorporated into the calculations. (2) All volumes in table are Company gross. (3) The oil volumes are quoted as Stock Tank Barrels ( STB ). (4) Sproule s analysis identified four intervals in the Montney consisting of one interval in the Upper Montney and three intervals in the Lower Montney. (5) Crew s acreage was divided into five (5) areas in the oil window. 3% 7% 2% Reserves and Risked and Unrisked Economic Contingent Resource (1)(2)(3)(6)(7)(8) Conventional Natural Gas (Bcf) Reserves (3) Development Pending ECR Development on Hold ECR Natural Gas Liquids (mmbbls) (4)(5) Reserves (3) Development Pending ECR Development on Hold ECR Light & Medium Crude Oil (mmbbls) Reserves (3) Development Pending ECR Development on Hold ECR Chance of Development 100% 87% 85% 100% 88% 84% 100% 90% 80% Best Estimate Unrisked 1,164 8, Best Estimate Risked 1,164 7, (1) All DPIIP other than cumulative production, reserves, and ECR has been categorized as unrecoverable at this time. A portion of the Unrecoverable DPIIP may in the future be determined to be recoverable and reclassified as contingent resources or reserves as additional technical studies are performed, 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. (2) All volumes in table are company gross and sales volumes, before economic cutoff. (3) For reserves, the volumes 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) There is no certainty that it will be commercially viable to produce any of the resources. (7) All ECR are risked for the chance of development. For ECR, the chance of development is defined as the probability of a project being commercially viable. In quantifying the chance of development, contingencies that were assessed quantitatively to be less than one in the risking calculation included evaluation drilling, corporate commitment and timing of production and development. The chance of development is multiplied by the unrisked resource volume estimate, which yields the risked volume estimate. As many of these factors have a wide range of uncertainty and are difficult to quantify, the chance of development is an uncertain value that should be used with caution. (8) The economic status of the development not viable project maturity subclass is deemed to be undetermined and is therefore not included in the ECR reported, representing, on a risked basis, 127 bcf of conventional natural gas, 3 mmbbls of NGLs and 2 mmbbls of light and medium crude oil

29 NE BC MONTNEY RESOURCE EVALUATION, CONTINUED Prospective Resources (1)(2)(3)(4)(5)(6)(7) Chance of Commerciality Best Estimate Unrisked Best Estimate Risked Conventional Natural Gas (Tcf) NGL (MMbbl) Light & Medium Crude Oil (MMbbl) 65% 65% 66% 10, , (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. (3) The liquid yields are based on average yield over the producing life of the property. (4) Liquid yields are unique to each area. They are estimated based on gas composition of gas samples in the area and expected plant recoveries. (5) There is no certainty that it will be commercially viable to produce any of the resources. (6) Prospective resources are risked for the chance of discovery and the chance of development. For prospective resources, the chance of development multiplied by the chance of discovery is defined as the probability of a project being commercially viable. In quantifying the chance of commerciality, factors that were assessed quantitatively to be less than one in the risking calculation included evaluation drilling, corporate commitment and timing of production and development, along with the overall chance of discovery. The chance of commerciality is multiplied by the unrisked prospective resource volume estimate, which yields the risked volume estimate. As many of these factors have a wide range of uncertainty and are difficult to quantify, the chance of commerciality is an uncertain value that should be used with caution. (7) All prospective resources are subclassified as either the prospect or lead project maturity subclass. 29

30 30 DEFINITIONS OF OIL & 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. 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. Contingencies 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. Economic Contingent Resources ("ECR") are those Contingent Resources which are currently economically recoverable. Project Maturity Subclass Development Pending is defined as a contingent resource that has been assigned a high chance of development and the resolution of final conditions for development are being actively pursued. Project Maturity Subclass Development On Hold is defined as a contingent resource that has been assigned a reasonable chance of development, but there are major non technical contingencies to be resolved that are usually beyond the control of the operator. Project Maturity Subclass Development Unclarified is defined as a contingent resource that requires further appraisal to clarify the potential for development and has been assigned a lower chance of development until contingencies can be clearly defined. Project Maturity Subclass Development not Viable is defined as a contingent resource where no further data acquisition or evaluation is currently planned and hence there is a low chance of development. 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.

31 INFORMATION ON RESERVES, RESOURCES & OPERATIONAL INFORMATION General - 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. In accordance with Canadian practice, production volumes and revenues are reported on a company gross basis, before deduction of Crown and other royalties and without including any royalty interest, unless otherwise stated. Unless otherwise specified, all reserves volumes in this news release (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, 2015 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 recovery and reserve estimates contained herein are estimates only and there is no guarantee that the estimated reserves will be recovered. In relation to the disclosure of estimates for individual properties, such estimates may not reflect the same confidence level as estimates of reserves and future net revenue for all properties, due to the effects of aggregation. The Company's belief that it will establish additional reserves over time with conversion of probable undeveloped reserves into proved reserves is a forward-looking statement and is based on certain assumptions and is subject to certain risks, as discussed previously under the heading "Forward-Looking Information and Statements". Unaudited financial information - Certain financial and operating information included in this presentation for the quarter and year ended December 31, 2016 are based on estimated unaudited financial results for the quarter and year then ended, and are subject to the same limitations as discussed previously under Forward Looking Information. These estimated amounts may change upon the completion of audited financial statements for the year ended December 31, 2016 and changes could be material. Oil & Gas Metrics - This presentation contains metrics commonly used in the oil and natural gas industry, such as "recycle ratio", "finding and development costs", "finding and development recycle ratio", "finding, development and acquisition costs", "operating netbacks", reserves replacement and IRR. These terms do not have standardized meanings or standardized methods of calculation and therefore may not be comparable to similar measures presented by other companies, and therefore should not be used to make such comparisons. Management uses oil and gas metrics for its own performance measurements and to provide shareholders with measures to compare Crew's operations over time. Readers are cautioned that the information provided by these metrics, or that can be derived from the metrics presented in this presentation, should not be unduly relied upon. The following oil and gas metrics have the following meanings as used in this presentation: F&D and FD&A costs - The calculation of F&D and FD&A costs incorporates the change in FDC required to bring proved undeveloped and developed reserves into production. In all cases, the F&D or FD&A number is calculated by dividing the identified capital expenditures by the applicable reserves additions after changes in FDC costs. Both F&D and FD&A costs take into account reserves revisions during the year on a per boe basis. The aggregate of the costs incurred in the financial year and changes during that year in estimated FDC may not reflect total F&D costs related to reserves additions for that year. Finding and development costs both including and excluding acquisitions and dispositions have been presented in this presentation because acquisitions and dispositions can have a significant impact on our ongoing reserves replacement costs and excluding these amounts could result in an inaccurate portrayal of our cost structure. Recycle ratio - defined as operating netback per boe divided by F&D or FD&A costs on a per boe basis. Operating netback is calculated as revenue (including realized hedging gains and losses) minus royalties, operating expenses, and transportation expenses. Reserves Replacement Ratio - calculated as total reserve additions (including acquisitions net of dispositions) divided by annual production. Crew s 2016 estimated annual production averaged 22,844 boe/d. Type Wells - The Septimus and West Septimus type wells presented in slides 9 and 13 herein reflect the average per well proved plus probable undeveloped raw gas assignments (EUR) for Crew's area of operations, as derived from the Company's year end independent reserve evaluations prepared in accordance with the definitions and standards contained in the COGE Handbook. The type wells are based upon all Crew producing wells in the area as well as non-crew wells determined by the independent evaluator to be analogous for purposes of the reserve assignments. Internal Forecast curves incorporate the most recent data from actual well results and would only be representative of the specific drilled locations. There is no guarantee that Crew will achieve the estimated or similar results derived therefrom. Test Results and Initial Production Rates - A pressure transient analysis or well-test interpretation has not been carried out and thus certain of the test results provided herein should be considered to be preliminary until such analysis or interpretation has been completed. Test results and initial production rates disclosed herein may not necessarily be indicative of long term performance or of ultimate recovery. 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 6:1, utilizing a 6:1 conversion basis may be misleading as an indication of value. Resource estimates within this Presentation are based upon the independent resource evaluation prepared in accordance with COGE by Sproule Associates Limited effective December 31, 2014 and December 31, 2015, as indicated. 31

32 INFORMATION ON RESERVES, RESOURCES & OPERATIONAL INFORMATION This presentation contains references to estimates of oil and gas classified as TPIIP, DPIIP, UPIIP and ECR in the Montney region in NE BC 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 in 2015 using a one 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 oil and 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. 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 below under the heading "Forward Looking Information and Statements". Reference is made to Crew's press release dated May 5, 2016 for a discussion of the principal risks, uncertainties and contingencies associated with the recovery and development of the Resource estimates presented herein. 32

33 World-Class MONTNEY RESOURCE % 1P Reserves per Share Growth 2016 over ,000 Net Acres in the Montney 18+ billion BOE of TPIIP Resource