BUILDING OUR FUTURE IN THE MONTNEY

BUILDING OUR FUTURE IN THE MONTNEY Location, Location, Location Corporate Presentation November 2017

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 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 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 forwardlooking 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 forwardlooking 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 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. www.crewenergy.com 2

ABOUT CREW (TSX: CR) Liquids-focused, NE BC Montney producer Growth-oriented Montney producer with large, contiguous land base in NE BC Simple business strategy: Replicate the successful free cash flow generation achieved at Septimus 5X Access to diversified markets with operated infrastructure, increasing liquids production & higher heat content gas that commands a premium CAPITAL STRUCTURE SNAPSHOT millions Basic shares outstanding 149.0 Market capitalization @ $4.25/share $633 Q3 17 net debt (including working capital) $339.5 Enterprise value $973 Debt capacity ($235mm facility + $300mm sr. notes) $535 280,000+ net acres in the Montney 16+ billion BOE of TPIIP resource 9.2 Tcfe Risked Best Estimate ECR +40% forecast Montney production growth exit 16 to exit 17 275+ mmcf/d long-term takeaway capacity to diverse markets $2 billion NPV 10 BT value (2016) www.crewenergy.com 3

Q3 17 & RECENT HIGHLIGHTS Increased liquids weighting improves funds from operations Corporate: 23,251 boe/d Greater Septimus: 18,154 boe/d ( 17% vs. Q2 17) ~2,600 boe/d of shut-in production added $1MM to funds from operations Currently ~28,000 boe/d forecast to increase to 31,000 boe/d by end 17 with W. Septimus plant expansion completed in mid-november Crew deferred 7,500 boe/d through October to capture improved prices in November Funds from operations $25.0MM ($0.17/sh) 21% vs. Q2 17 Greater Septimus opex reduced to $3.38/boe ( 18% vs Q2 17 & 6% vs Q3 16) Corporate cash costs per boe 13% vs Q2 17 $89.9MM capex: 13 Montney drills, 16 NE BC completions (14 at liquids-rich Greater Septimus); W. Septimus expansion to 120 mmcf/d continued and tracking under budget 2 initial ultra condensate-rich wells have performed exceptionally: 1 st paid out in 9 mos. 3 ultra condensate-rich wells at W. Septimus after 10 days flowed at avg per well rate of 1,445 boe/d (824 bbls/d condy + 4.3 mmcf/d raw gas; CGR of 192 bbls/mmcf) 2 wells in transition zone between liquids-rich and ultra condensate-rich areas at W. Septimus after 10 days flowed at avg per well of 1,340 boe/d (420 bbls/d of wellhead condy + 5.6 mmcf/d raw gas; avg CGR of 75 bbls/mmcf) Average Price Pricing Hub Oct. Nov 1-6 Stn 2 ($/mcf) $0.33 $0.80 AECO 5A ($/mcf) $0.70 $2.59 ATP ($/mcf) $0.75 $2.55 WTI ($C/bbl) $65.04 $73.01 www.crewenergy.com 4

MAXIMIZING RETURNS FROM OUR RESOURCE It starts with the rock Build a material prospective land position at a low cost Define the resource and convert the prospective land to resource Convert the resource into reserves and production Proof of concept with achievement of free cash flow model (Septimus) Septimus 5X - continue to de-risk and high-grade portfolio and build out infrastructure (W. Septimus, Groundbirch, Attachie) Building towards free cash flow with our ~5,465 identified locations (1) People Assets Technology (1) Identified locations are the total number of risked Contingent (1,953) and Prospective (3,160) resource locations as well as the 2P booked undeveloped Montney locations (356) identified in Crew s annual year end independent resource evaluation and independent reserves evaluation, both prepared in accordance with the COGE Handbook provisions and NI 51-101. See complete details on the resource evaluation and reserves evaluation in presentation appendix. www.crewenergy.com 5

SIGNIFICANT PROSPECTIVE LAND POSITION BUILT And for low cost 280,000 acres for net $285/acre Montney (2007) Montney (2010) Montney (2017) 2010 2017, Crew sold >$700 MM of non-core assets to focus on our Montney development Date Area Divested Value ($mm) Production (boe/d) Land (acres) Apr 2010 Edson Cardium $126 1,700 32,000 Dec 2012 Kobes (Montney) $108 625 15,800 May 2014 Deep Basin Gas $222 7,000 254,000 Aug 2014 Princess $150 3,650 259,230 Sep 2015 Heavy Oil Package $50 225 11,670 May 2017 Goose (Montney) $49 0 18,400 TOTAL $705 13,200 591,100 www.crewenergy.com 6

CONVERTING PROSPECTIVE LAND TO RESOURCE Montney is a siltstone, not a shale Montney Attributes: Exceptionally thick: up to 1,000 feet Permeability 20-80x greater than comparable resource plays in North America Excellent fracability Lowest royalty regime in North America Source: RBC Capital Markets, September 2017 444 net sections 266 Wet Gas Sections 113 Oil / Condensate Sections 65 Dry Gas Sections Only 13% of Crew s Upper Montney and <1% of Lower Montney lands have reserves assigned www.crewenergy.com 7

Lower Montney 1,000 Feet Upper Montney CREW MONTNEY STRATIGRAPHIC STACK 2 HZ Wells 4 HZ Wells 3 HZ Wells 72 HZ Wells 77 HZ Wells 10 HZ Wells West Portage Groundbirch Attachie West Septimus Septimus Tower Doig 1 AA 1 7 23 7 2 3 A B C 2 47 14 1 42 9 2 3 3 Monias High 1 168 Crew HZ wells drilled to Q3, 2017 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 www.crewenergy.com 8 Belloy

$/boe CONVERTING RESOURCE TO PRODUCTION & RESERVES And do it for low cost 350.0 P+P Reserves (2) (MMBOE) 323.9 30,000 Montney Production (1) (BOE/D) Forecast 300.0 250.0 200.0 150.0 100.0 50.0-15.3 Liquids mmbbls Gas mboe 21.6 27.7 46.7 48.1 99.2 201.9 246.5 2008 2009 2010 2011 2012 2013 2014 2015 2016 25,000 20,000 15,000 10,000 5,000 0 Natural Gas boepd NGLs boepd Light oil bopd 2009 2010 2011 2012 2013 2014 2015 2016 2017 2017 exit $16 $12 $8 $4 $0 $14.45 $9.88 3 Year Average F&D (2)(3)(4) $11.08 $8.38 $9.15 $7.39 2014 2015 2016 (1) Reflects production from Greater Septimus, Tower & Groundbirch. (2) Based on Crew s annual year end independent reserves evaluations. 1P F&D 2P F&D 6.0 5.0 4.0 3.0 2.0 1.0-1.6 2.5 F&D Reserve Recycle Ratios (2)(3)(4) (3) All F&D figures include change in future development capital. (4) See Appendix for definitions and methodology for calculation of F&D and recycle ratio. www.crewenergy.com 9 5.1 3.4 2.7 2014 2015 2016 3.0 1P Recycle 2P Recycle

$MM PROOF OF CONCEPT WITH SEPTIMUS Achieved free cash flow model $100 $90 $80 $70 $60 $50 $40 $30 $20 $10 Cash Flow Capex ~$89 MM Free cash flow forecast 16 19 (2) Free cash flow directed to fund continued Montney growth Long-range growth plan forecasts free cash flow equivalent to Septimus multiplied by 5 Average Per Well Economics (1) Full Cycle Half Cycle Capital Expenditures ($MM) $4.6 $3.8 1 Month IP (boe/d) 809 809 Liquids (mbbls) 169 169 Sales Gas (bcf) (raw: 5.6 bcf) 5.2 5.2 Total Reserves (mboe) 1,037 1,037 ROR Before Tax (%) 36% 55% $- 2013 2014 2015 2016 2017 2018 2019 Forecast (3) (3) (1) Assumptions: Based on Sproule s year end 2016 2P type wells for Septimus and Cal 17: C$2.63/GJ AECO; US$49.61 WTI, $0.77 F/X, and flat price deck for Cal 18 and 19: C$2.75/GJ AECO; US$50.00 WTI, $0.80 F/X. (2) Price deck for cash flow forecast: Cal 17: C$2.63/GJ AECO; US$49.61 WTI, $0.77 F/X, and flat price deck for Cal 18 and 19: C$2.75/GJ AECO; US$50.00 WTI, $0.80 F/X. (3) Assumes average capital with infrastructure capital excluded. www.crewenergy.com 10

Daily Gas Production (mcf/d) WEST SEPTIMUS: CONDENSATE RICH Plant expansion to 120 mmcf/d plus high condensate rates accelerates free cash flow generation 2x Initial Condensate Ratios vs. Septimus Higher liquids weighting contributes to a better return on capital and will help W. Septimus reach free cash flow generation in shorter time frame than Septimus 10000 9000 8000 7000 6000 5000 4000 3000 2000 1000 Outperformance of Initial West Septimus Type Curve (2)(3) 0 0 50 100 150 200 250 300 350 400 04-24 (9) Time (Days) 05-24 (3) 07-30 (2) 09-17 (5) 10-16 (7) 16-15 (6) 08-22 (3) 2016YE Sproule - 5.0Bcf 2P (2) See the Appendix to this presentation for information on Type Wells. (3) 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. Average Per Well Economics (1) Full Cycle Half Cycle Capital Expenditures ($MM) $4.6 $3.8 1 Month IP (boe/d) 1,029 1,029 Liquids (mbbls) 197 197 Sales Gas (bcf) (raw: 5.0 bcf) 4.7 4.7 Total Reserves (mboe) 980 980 ROR Before Tax (%) 38% 61% (1) Assumptions: Based on Sproule s year end 2016 2P type wells for West Septimus and Cal 17: C$2.63/GJ AECO; US$49.61 WTI, $0.77 F/X, and flat price deck for Cal 18 and 19: C$2.75/GJ AECO; US$50.00 WTI, $0.80 F/X. www.crewenergy.com 11

ULTRA CONDENSATE-RICH AREA New focus at Greater Septimus Ultra Condensate-Rich Crew 4-22 Pad Crew 6-24 Pad 2 wells: 1,340 boepd 420 bbls/d condy Crew 7-30 Pad 3 wells: 1,445 boepd 824 bbls/d condy C7-30: 83,000 bbls condensate in 326 days; avg CGR of 168 Well paid out in 9 months B7-30: 59,000 bbls condensate in 211 days; avg CGR of 120 Crew 13-19 Pad Completion Operations Significant long-term future development potential in the area. Condensate-rich with low capital and operating costs provide superior returns Average Per Well Economics (1) Half Cycle Capital Expenditures ($MM) $4.8 Crew 15-9 Pad Crew 15-10 Pad Drilling Operations W. Septimus Facility 60 mmcf/d Capacity Expanding to 120 mmcf/d Q4 2017 1 Month IP (boe/d) 1,064 Liquids (mbbls) 304 Sales Gas (bcf) 3.5 Total Reserves (mboe) 892 Montney 2017 Drilling Locations Montney Drilled Wells Crew Montney Acreage Ultra Condensate Rich Area ROR Before Tax (%) 95% (1) Assumptions: Based on Sproule s year end 2016 2P type wells for Septimus and flat price deck for Cal 18 and 19: C$2.75/GJ AECO; US$50.00 WTI, $0.80 F/X. www.crewenergy.com 12

GROUNDBIRCH Delineation area with long-term upside Higher liquids content than Septimus at 40 bbls / mmcf, 60% condensate Large pay thickness (500 ft. Upper Montney) with expected development of 15-20 wells / section in Upper Montney 156 sections of land: recent land sale illustrates value of area land at $3.53MM per section Read through for Crew at ~$550MM Groundbirch Development Plan (1) Recent Landsale $2.1MM / Section Crew 2-4 Pad 2 wells: 5.1 mmcf/d 108 bbls/d condy Acquisition of 10 Sections of Surface Rights Groundbirch 2018/19 Planned Facility 120 mmcf/d Capacity Recent Landsale $3.5MM / Section W. Septimus Facility 60 mmcf/d Capacity Expanding to 120 mmcf/d MS TCPL Saturn Meter Station 2017 2018 2019 2020+ Delineation Build Gas Plant + Pipeline from W. Septimus to Saturn Meter Station Area Development (1) Assumes flat price deck of $2.75/GJ AECO; $US50.00/bbl WTI, FX $0.80. Montney Phase 1 Locations (230) Montney Drilled Wells Crew 2017/2018 Pipeline Construction Proposed TCPL N. Montney Mainline Project CN Railway Line Crew Operated Pipeline Crew Montney Acreage www.crewenergy.com 13

ATTACHIE Pilot wells successful Over-pressured 1.5-1.8x with liquids-rich natural gas Large pay thickness (1,000 Upper + Lower Montney) High condensate rates in offsetting wells (>100 bbls/mmcf) Ideally situated to access proposed N. Montney Mainline Crew 10-22 well tested at 10.5 mmcf/d @ 1,230 psi FCP (after 4 days flow) (1) Crew 15-36 well tested at 7.9 mmcf/d @ 1,250 psi FCP (after 2.5 days flow) (2) Several prolific offsetting producers in Upper and Lower Montney July 2017 land sale illustrates value of area land at $3.7MM per section. Crew has 97 sections at Attachie (1) Reflects stabilized natural gas rate at end of 4 day test period. (2) Reflects stabilized natural gas rate at end of 2.5 day test period. Crew 10-22 10.5 mmcf/d Extreme Overpressured 4 Fracs Extreme Overpressure Area Crew C-20-E Final Rate 4.4 mmcf/d 4 Fracs July 2017 Landsale 21 Sections $77MM $3.7 MM / Section Crew 3-12 Final Rate 2.4 mmcf/d 5 Fracs B13-26-84-24W6 CGR: 350 bbls/mmcf IP30: 665 bbls/d condy Crew 15-36 Final Rate 7.8 mmcf/d Increasing Liquids Content 19 Fracs Crew 10-22 Montney Well 13-14-84-24W6 CGR: 320 bbls/mmcf IP30: 1,020 bbls/d condy Crew 15-36 Montney Well Spectra T North Pipeline Proposed TCPL N. Montney Mainline Project Crew Montney Acreage www.crewenergy.com 14

SEPTIMUS 5X MODEL Inventory of ~5,465 identified drilling locations(1) supports processing capacity + growth Future Growth Supported by Operated Infrastructure 1x Septimus: 60 mmcf/d 104 identified locations & 6 wells per year to keep production flat W. Septimus Ultra condensaterich area 2x W. Septimus: 120 mmcf/d 512 identified locations 2x 2x Groundbirch: 120 mmcf/d 2x Groundbirch 1x 156 net sections of land currently being delineated Septimus Identified locations are the total number of risked Contingent (1,953) and Prospective (3,160) resource locations as well as the 2P booked undeveloped Montney locations (356) identified in Crew s annual year end independent resource evaluation and independent reserves evaluation, both prepared in accordance with the COGE Handbook provisions and NI 51-101. See complete details on the resource evaluation and reserves evaluation in presentation appendix. (1) www.crewenergy.com 15

mmcf/d CONTINUE DE-RISKING AND HIGH GRADING PORTFOLIO WITH STAGED INFRASTRUCTURE BUILDOUT 275 mmcf/d takeaway capacity with 325 mmcf/d of processing Transportation TCPL/Nova: 60 mmcf/d firm increasing to 120 mmcf/d (Jun 19) Spectra: 30 mmcf/d firm Flatrock 350 300 250 200 150 100 50 0 Alliance: Processing 100 mmcf/d firm (+ 25 priority interruptible available) # s above do not include access to interruptible or shorter term transportation opportunities Groundbirch: 120 mmcf/d (Proposed) W. Septimus: 60 mmcf/d expanding to 120 mmcf/d (Q4 17) Additional capacity post- * 2020 is available on the TCPL / Nova System Septimus: 60 mmcf/d Other: 25 mmcf/d * Jan-17 Jul-17 Jan-18 Jul-18 Jan-19 Jul-19 Jan-20 Portage Spectra T-North Ft. Nelson Mainline 1.4 Bcf/d Attachie TCPL N. Montney Project 1.5 Bcf/d Spectra T-North Ft. St. John Mainline 0.85 Bcf/d (post expansion) Groundbirch 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 CN Railway Line West Septimus Septimus Tower Alliance Pipeline 1.6 Bcf/d www.crewenergy.com 16 MS Crew 9-28 Gas Plant & 10-28 Oil Battery MS 10 Miles Crew Operated Gas Plant Crew Planned Gas Plant Spectra McMahon Gas Plant TCPL Saturn Meter Station Crew Montney Acreage

Natural Gas Prices ($C/MCF) REALIZED IMPACT OF GAS MARKET DIVERSITY Ideally positioned with access to 3 major export pipelines $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 18% Higher heat content gas realizes premium to AECO benchmark Crew s Gas Market Diversity Q3, 2017 ATP AECO 5A Stn 2 7% 19% 35% 39% Chicago City Gate $ - Nov-15 Dec-15 Q1 2016 Q2 2016 Q3 2016 Q4 2016 Q1 2017 Q2 2017 Q3 2017 (1) Crew Realized Price Chicago City Gate at ATP AECO 5A ATP (CREC) Stn #2 (1) Wellhead price before impact of hedging. www.crewenergy.com 17

CONTROLLING COSTS & MAXIMIZING NETBACKS Montney assets continue to generate attractive netbacks $25 Rolling One Year (to Q2 17) Operating Netbacks (Pre-Hedging) for Montney-Focused Peers ($/boe) Top Quartile Rolling One Year (to Q2 17) Operating Costs Among Montney-Focused Peers ($/boe) $12 $20 $15 Group Average = $15.48 $15.80 $17.37 $10 $8 Group Average = $6.43 $6 $5.62 $10 $4 $3.58 $5 $2 $0 8 9 7 5 6 4 CR Corp 3 2 CR Greater Septimus 1 $0 7 CR Greater Septimus 8 5 1 CR Corp 9 3 6 4 2 Source: NBF. Companies included in above analysis include VII, NVA, TET, POU, BIR, KEL, AAV,PONY, SRX. www.crewenergy.com 18

IRR BT (%) IRR BT (%) COMPELLING RETURNS FROM MONTNEY ASSETS Across a variety of price & cost cycles Project Area Cost Increase Effect on IRR (BT) Project Area Price Increase Effect on IRR (BT) 100 90 80 $4.8MM ~50% IRR even with 25% cost escalation 160 140 ~147% IRR with 15% price increase 70 60 $3.8MM 120 100 50 40 30 20 10 $3.8MM 80 60 40 20 0-5 0 5 10 15 20 25 Cost Increase (%) Septimus West Septimus Condensate Rich 0-20 -15-10 -5 0 5 10 15 Commodity Price Variance (%) Septimus West Septimus Condensate Rich (1) Assumptions: Based on Sproule s year end 2016 2P type wells for Septimus, W. Septimus, and Ultra-condensate rich area. Flat price deck for Cal 18 and 19: C$2.75/GJ AECO; US$50.00 WTI, $0.80 F/X. www.crewenergy.com 19

KEY MONTNEY BUILDING BLOCKS ARE IN PLACE Increasing Condensate Massive Resource Efficiency Improvements Significant Exit to Exit Production Growth Access to Operated Infrastructure Financial Strength Focus on condensate-rich development to drive improved cash flows Quicker well payouts with improving netbacks 16+ billion boe TPIIP with ~5,465 identified locations (1) on >280,000 net acres Only 13% of Upper Montney land has reserves assigned Lower costs, higher IPs and EURs per well Focus on early payouts to drive returns +40% 2017 over 2016 ~31,000 boe/d forecast Owned and operated infrastructure with processing and transportation options to multiple markets Cost controls and market diversity = higher netbacks $535 million of available debt capacity; $300 million of debt termed out to 2024 Capital structure aligned with long term plan (1) Identified locations are the total number of risked Contingent (1,953) and Prospective (3,160) resource locations as well as the 2P booked undeveloped Montney locations (356) identified in Crew s annual year end independent resource evaluation and independent reserves evaluation, both prepared in accordance with the COGE Handbook provisions and NI 51-101. See complete details on the resource evaluation and reserves evaluation in presentation appendix. www.crewenergy.com 20

Contact Info: 21 Dale O. Shwed, President & CEO John G. Leach, Senior Vice President & CFO Suite 800, 250-5th Street SW Calgary, Alberta T2P 0R4 Telephone: (403) 266-2088 Email: investor@crewenergy.com www.crewenergy.com 21

APPENDIX www.crewenergy.com 22

2017 CAPEX PROGRAM & FORECAST 2017 Cash Flow (CF) (mm) $110 Capex (mm) $235 Year-end net debt (mm) $337 Debt to annualized Q4 CF 2.4x Assumptions: Production guidance (boepd) 23,000-24,000 Pricing Gas (AECO-C$/mcf) $2.20 Oil (WTI-C$/bbl) $65.60 WTI to WCS diff. 24% FX ($US/$CDN) $0.77 Interest rate-bank debt 4.5% Interest rate-high yield 6.5% Royalties 6-8% Op. costs ($/boe) $5.50-6.00 Transportation ($/boe) $2.25-2.50 G&A ($/boe) $1.25-1.50 Interest Expense ($/boe) $2.40-2.60 Hedging Summary as of Nov 2, 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 5,000 mmbtu/day 2018 Swap NYMEX US$3.05/mmbtu Oil 1,750 bopd Jan Dec 2017 Swap $C WTI / bbl C$68.02 500 bopd Jan Dec 2018 Swap $C WTI / bbl C$67.14 250 bopd Jan Dec 2018 Collar $C WTI / bbl C$60.00 x $69.65 www.crewenergy.com 23

TRACK RECORD OF PROFITABILITY SUPPORTED BY LOW COSTS $60 2016 PDP FD&A Costs ($US/boe) $30 2016 Cash Costs ($US/boe, net of royalties) $50 Canadian Co's US Co's Median $25 Canadian Co's US Co's Median $40 $20 $30 $15 $20 $10 CR $10 CR $5 $0 18 13 1 10 35 28 11 15 23 7 42 44 46 41 33 4 22 9 39 12 37 17 31 25 43 40 14 20 38 16 34 24 6 3 27 19 2 26 36 45 $0 1 283913 7 8 15343346 5 1243324441262230422123172019241016354027361431 3 4 18 9 2938 2 45371125 6 (1) Source: Macquarie Capital Markets Canada; May 30 17. See appendix for list of companies that correspond to the numbers referenced in the analysis. www.crewenergy.com 24

TOP QUARTILE CAPITAL EFFICIENCIES DRIVE STRONG RECYCLE RATIOS $60 3-Year Proved Developed FD&A Costs ($US/boe, net of royalties) 3.5x 3-Year Proved Developed Recycle Ratio ($US/boe, net of royalties, including hedging) $50 Canadian Co's US Co's Median 3.0x Canadian Co's US Co's Median 2.5x $40 2.0x $30 CR 1.5x $20 1.0x $10 CR 0.5x $0 132133 7 8 28 1 15 5 114639423510 4 4144344323253731 3 124020162422142717294536321826 9 19 2 6 0.0x 2113 5 422528 8 1535 7 343344 1 16 4 1112143146403723272041 3 45243243102639 6 361917 9 2 222918 (1) Source: Macquarie Capital Markets Canada; May 30 17. See appendix for list of companies that correspond to the numbers referenced in the above analysis www.crewenergy.com 25

EV/DACF 2018 VALUE / PROFITABILITY DISCONNECT 14.0x 12.0x 10.0x 8.0x 6.0x 4.0x Revenue - PDP FD&A Costs - Cash Costs = Full Cycle Profitability BBG ECA APA EGN PDCE POU BTE SM DVN KEL PE WLL NFX APC SN CHK NBL VII SWN PXD RMP AREX TVE CXO EOG RRC OAS CJ CPG XEC COG AAV CLR TOG CR SGY BIR WCP BNP ARX PEY ERF VET US Co's Canadian Co's RRX Increasing valuation 2.0x ($50) ($40) ($30) ($20) ($10) $0 $10 $20 (1) Source: Macquarie Capital Markets Canada; EV as at July 24 17. Increasing profitability 3 Year Full Cycle Profit (ex-hedge) www.crewenergy.com 26

DEFINITIONS OF OIL & GAS RESOURCES & 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. www.crewenergy.com 27

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, 2016 includes complete disclosure of our oil and gas reserves and other oil and gas information in accordance with NI 51-101, and is contained within our Annual Information Form which is available on our SEDAR profile at www.sedar.com. 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 annual production averaged 22,844 boe/d. Type Wells - The Septimus and West Septimus type wells referenced 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, 2015 and December 31, 2016, as indicated. www.crewenergy.com 28

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 2016 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. Companies included in the analyses on slides 24-26: AAV 1 APA 2 APC 3 AREX 4 ARX 5 BBG 6 BIR 7 BNP 8 BTE 9 CHK 10 CJ 11 CLR 12 COG 13 CPG 14 CR 15 CXO 16 DVN 17 ECA 18 EGN 19 EOG 20 ERF 21 KEL 22 NBL 23 NFX 24 OAS 25 PDCE 26 PE 27 PEY 28 POU 29 PRQ 30 PXD 31 RMP 32 RRC 33 RRX 34 SGY 35 SM 36 SN 37 SPE 38 SWN 39 TOG 40 TVE 41 VET 42 VII 43 WCP 44 WLL 45 XEC 46 www.crewenergy.com 29