Focus on Value Creation. February 2019

Transcription

1 Focus on Value Creation February 2019

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 forward-looking information and statements pertaining to the following: Crew s 2018 and 2019 budget; 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 2018 and 2019 forecast average production and 2018 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; anticipated credit facility draws in 2019; future results from operations and operating metrics; forecast 2018 and 2019 net debt; forecast 2018 and 2019 free cash flow and cash flow estimates; year end net debt; forecast net debt to annualized Q4 cash flow; 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 2018 and 2019 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 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. 2

3 ABOUT CREW (TSX: CR) Liquids-focused, NE BC Montney producer Large, contiguous land base with a material resource >16 billion boe Access to diversified markets with operated and growing infrastructure footprint, increasing liquids production & higher heat content gas yields a premium price Current infrastructure supports growth to over 40,000 boe/d Material leverage to condensate; a 1,000 bbls/d increase drives funds flow increase of 21% (1) CAPITAL STRUCTURE SNAPSHOT millions Basic shares outstanding Market $0.90/share $137 Long term debt as at September 30, 2018: Senior unsecured notes due 2024 (2) $295 Bank debt + working capital $38 INVESTMENT ATTRIBUTES 282,000+ net acres in the Montney 63% of field netback from liquids production in Q3/18 (3) 411 MM boe of reserves (2018) = 2.7 boe of reserves / share 275+ mmcf/d long-term takeaway capacity to diverse markets Enterprise value $470 $2.5 billion NPV 10 BT value (2018) (1) See inputs for rate of return & payout calculations in the appendix for assumptions used to arrive at amount (2) Net of deferred financing costs of $5 million (3) Field netback = Operating Netback before hedging gains / loss 3

4 SIGNIFICANT LAND POSITION Acreage prospectivity & land value affords material optionality Montney (2007) Montney (2010) Montney (2019) Crew has sold ~$715 MM of assets and maintains optionality to sell additional assets to further support our Montney development Date Area Divested Value ($mm) Production (boe/d) Land (acres) Apr 2010 Edson (Cardium) $126 1,700 32,000 Dec 2012 Kobes (Montney) $ ,800 May 2014 Deep Basin Gas $222 7, ,000 Aug 2014 Princess $150 3, ,230 Sep 2015 Heavy Oil Package $ ,670 May 2017 Goose (Montney) $ ,400 Mar 2018 Heavy Oil Package $ TOTAL $715 13, ,

5 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 Crew Energy Inc. Arc Resources CNRL Canbriam ConocoPhillips Encana Fireweed Kelt Leucrotta Painted Pony Pengrowth Primavera Progress Sanling Shell Storm Tourmaline Broker Lands Other Leaseholders Freehold Lands 443 net sections 266 Wet Gas Sections 116 Oil / Condensate Sections 61 Dry Gas Sections Source: RBC Capital Markets September 2018 Only 13% of Crew s Upper Montney and <1% of Lower Montney lands have reserves assigned 5

6 $/boe 2018 YEAR END RESERVES HIGHLIGHTS (1) Outperformance drives further condensate growth 3 year Average 2P F&D Trending Down $16 $14 $12 $10 $8 $6 $14.45 $9.88 $11.08 $8.38 $9.15 $7.39 $ Year 1P F&D 3 Year 2P F&D $7.48 $5.92 $5.87 Condensate Growth at West Septimus UCR 1P Condensate Reserves +30% $4 $2 $ F&D Recycle 2018 PDP 1.4 x 1P 2.3x 2P 3.4x UCR Area 2P NPV 10 (based on 14 sections) $774.1MM (1) Based on Crew s December 31, 2018 annual year end independent reserves evaluation. 6

7 $/boe CONVERTING RESOURCE TO PRODUCTION & RESERVES At a low cost P+P Reserves (2) $10 $8 $6 $4 $2 $0 Liquids mmbbls Gas mboe $9.15 (MMBOE) Year Average F&D (2)(3)(4) $ $ Year 1P F&D 3 Year 2P F&D $7.48 $5.92 $ (1) Reflects production from Greater Septimus, Tower & Groundbirch (2) Based on Crew s annual year end independent reserves evaluations Montney Organic Production Growth (1) (BOE/D) 22,000 20,000 18,000 16,000 14,000 12,000 10,000 8,000 6,000 4,000 2, Condensate bopd NGLs bopd Light Oil bopd Natural Gas boepd 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 Focus on condensate 1P Recycle 2P Recycle 3.4

8 Lower Montney 1,000 Feet Upper Montney CREW MONTNEY STRATIGRAPHIC STACK 2 HZ Wells 4 HZ Wells 3 HZ Wells 87 HZ Wells 77 HZ Wells 10 HZ Wells West Portage Groundbirch Attachie West Septimus Septimus Tower Doig 1 AA A B C 2 Upper Montney Lower Montney 3 Monias High Crew HZ wells drilled to Q4, 2018 Prospective Belloy 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 8

9 $MM AECO Gas Price $/mcf STABLE PRODUCTION BASE = Free cash flow at Septimus $100 $90 $80 $70 $60 $50 $40 $30 $20 $10 $- $3.57 $4.49 $2.37 $2.16 $2.16 $1.70 $ Forecast (3) AECO Gas Price ($/mcf) ~$96MM Free cash flow forecast (2) (16/17 actuals & 18/19 forecast) Cash Flow Free cash flow directed to fund UCR growth Capex $5.00 $4.00 $3.00 $2.00 $1.00 $- Long-range growth plan forecasts W. Septimus & Groundbirch generating free cash flow in excess of 2X Septimus from additional liquids. Average Per Well Economics (1) Half Cycle Capital Expenditures ($MM) $4.0 1 Month IP (boe/d) 809 Liquids (mbbls) 169 Sales Gas (bcf) (raw: 5.6 bcf) 5.2 Total Reserves (mboe) 1,037 IRR Before Tax (%) 49% (1) Assumptions: Based on the Sproule Reserve Report 2P type wells for Septimus and flat price deck of US$3.00/MMBtu NYMEX, $1.55/Gj AECO, US$52.00/bbl WTI, $0.76 F/X (2) Price deck for cash flow forecast - Cal 18 includes first nine months actuals and Q4 estimates. Cal 19 uses flat price deck: US$3.00/MMBtu NYMEX, $1.55/Gj AECO, US$52.00/bbl WTI, $0.76 F/X (3) Assumes average capital with infrastructure capital excluded 9

10 ULTRA CONDENSATE-RICH ( UCR ) AREA Focus at Greater Septimus > Focus on UCR development UCR Area > Condensate ratios of bbls/mmcf in area > 69% IRR on forward strip pricing (1) Crew 7-30 Pad IP 60: 5 well average: 350 bbls/d condy 172 bbls/mmcf CGR Crew 3-32 Pad Q drilling 138 Tier 1 ERH $5.9MM NPV 10 per ERH well Transition Zone Crew Pad 8 wells average: IP mmcf/d 141 bbls/d condy 35 bbls/mmcf CGR Liquids-Rich Area Crew Pad, 3 wells per well average: 1,528 boed 776 bbls/d condy 153 bbls/d NGLs 216 bbls/mmcf CGR Crew 4-21 Pad 6 wells drilling operations >75 bbl/mmcf >200 bbl/mmcf Crew Montney B Zone Locations Crew Montney C Zone Well Crew Montney Drilled Wells Crew Recent Acquired Lands Crew Montney Acreage $814MM Of value vs Crew s $470MM EV 1.1 MMboe Reserves/well 31% Condensate (1) Assumptions: Based on Sproule s year end P type wells for West Septimus and forward strip price deck for which assumes AECO per GJ of $1.50, $1.57, $1.63, $1.73, $1.88; and WTI (CAD) per bbl of $71.65, $70.50, $69.50, $68.50, $

11 $/lateral metre Increasing Depth (metres) EXCEPTIONAL OPERATIONAL PERFORMANCE Pacesetter well performance on first ERH pad Costs per Lateral Length Continue to Improve Drilling Days vs Depth $1,200 $1,000 $800 $600 $400 34% Pacesetter performance on 2018 s first pad Days 2018 vs 2016 / % Lateral length 18% Increase in depth 4000 $ $ Pacesetter Pacesetter 2018 YTD Pacesetter 11

12 Condensate Sales (bbl per well) ~1,800 m UCR COMPLETION EVOLUTION Positive early results 25,000 Initial 30 Day Condensate 20,000 Montney 15,000 10, Pad, 3 wells 3 well rate 4,584 boe/d Per well average: 1,528 boe/d 776 bbls/d condy 153 bbls/d NGLs 216 bbls/mmcf CGR The total depth to (and thickness of) the Montney is not illustrated to scale 5,000 Previous Design 7-30 Pad Open-hole ball drop Slickwater fluid 1,600 2,000m lateral length 400m interwell spacing New Design Pad Plug & perf completions Slickwater and hybrid test 2,500-2,700m lateral length 250m interwell spacing Cluster spacing trial, microseismic Four fold increase in fracture initiation points Production Days Pad Previous UCR Transition Zone Liquids Rich 12

13 Rate of Return (%) WEST SEPTIMUS: ULTRA CONDENSATE-RICH Compelling IRRs and robust NPVs of ERH wells support continued development with low gas prices Rate of Return Sensitivities (1) to WTI Pricing (US$/bbl) 147% IRR Natural Gas: US$3.00/MMBtu NYMEX, C$1.55/mcf AECO, FX: $0.76 WTI Assumption US$/bbl $40 $50 $60 $ % IRR 62% IRR Rate of Return (1) Liquids-Rich Area 41% 48% 54% 62% Transition Zone 39% 53% 72% 95% Ultra Condensate-Rich ( UCR ) Area 48% 73% 105% 147% 20 0 $35 $40 $45 $50 $55 $60 $65 $70 Oil Price (USD/bbl) Average IP Condensate Gas Ratios: Liquids Rich Area Transition Zone Long UCR 20 to <75 bbls/mmcf 75 to 200 bbls/mmcf (3) >200 bbls/mmcf NPV (1,2) ($MM) Liquids-Rich Area $2.5 $2.9 $3.3 $3.8 Transition Zone $3.7 $4.9 $6.0 $7.2 UCR Area $4.3 $5.9 $7.5 $9.1 (1) See input assumptions in table on Slide 28. (2) Net Present Values (NPVs) discounted at 10%. (3) UCR wells increased lateral well length from 1,800m to 2,500m 13

14 STRATEGICALLY POSITIONED LAND BASE NE BC Montney assets are ideally situated for export RAILWAY TRANSPORTATION Uniquely positioned land base with direct access to 3 existing export pipelines, potential LNG exports & rail transportation RAILWAY TRANSPORTATION Map source: Desjardins Securities COASTAL GAS LINK LNG CANADA Crew Montney Land Base 14

15 OTHER OPPORTUNITIES Attachie, Groundbirch, Monias, and Tower development ATTACHIE Over-pressured x with liquids-rich natural gas Large pay thickness (1,000 ft. Upper + Lower Montney) High condensate rates in offsetting wells (>300 bbls/mmcf) One Q lease retention well currently drilling GROUNDBIRCH Higher liquids content than Septimus at 40 bbls/mmcf, 60% condensate Large pay thickness (500 ft. Upper Montney) with expected development of wells / section in Upper Montney Recent land sale at $3.53MM per section supports value of Crew s land in the area (156 sections) MONIAS B13-26 Pad CGR: 350 bbls/mmcf IP30: 665 bbls/d condy Crew mmcf/d extreme overpressured 4 fracs 6 Miles Pad 7 well average: IP mmcf/d, 422 bbls/d condy CGR 301 bbls/mmcf Crew lease retention well Crew final rate 7.8 mmcf/d increasing liquids content 19 fracs Attachie Crew C-20-E final rate 4.4 mmcf/d completed Jan fracs Monias 2019 exploratory well West Septimus Alliance pipeline 1.6 Bcf/d Monias TCPL N. Montney project 1.5 Bcf/d Tower Recent landsale 2.1MM / section Crew 3-12 final rate 2.4 mmcf/d completed Sept fracs Septimus Spectra T-North Ft. Nelson Mainline Groundbirch 1.4 Bcf/d Recent landsale $3.5MM / section One exploratory well planned in 2019 Crew oil battery & 10-4 Pads 11 well avg IP60 ~12 mmcf/d dry gas TCPL Saturn meter station MS Spectra T-North Ft. St. John Mainline 0.85 Bcf/d (post expansion) TOWER Light sweet oil API Crew is monitoring offset drilling results Crew Operated Pipeline Pembina Peace Condensate Pipeline Crew Operated Gas Plants Crew 2018 Pipeline Construction TCPL Operated Pipeline Crew Planned Gas Plant Alliance Operated Pipeline TCPL North Montney Mainline Project - Approved Spectra McMahon Gas Plant Spectra Westcoast Operated Pipelines CN Railway Line Crew Montney Acreage Within the map above, final rate is defined as the last 6 hours of the flowback test 15

16 MARKET DIVERSIFICATION Expanding exposure to higher-priced hubs outside of Canada (2) Chicago Dawn (1) Malin (1) Nymex Sumas (1) AECO ATP Station 2 Q Q2 & Q Q % 3% 6% 6% 18% 15% 19% 41% 38% 12% 4% 44% 48% 37% (1) % 10% 4% 16% 8% 15% 43% Q1 (1) Exposure to Dawn, Malin & Sumas markets were monetized financially for Q2 & Q3 recognizing $3.9mm of marketing revenue and again for Q4 recognizing $3.2mm of marketing revenue ($2.1 mm after deduction of transportation costs) (2) Estimated market allocations are based on current forward market prices and estimated production levels Q

17 PRODUCTION AND MARKET DIVERSIFICATION Increasing condensate production and greater exposure to US Nat Gas markets Q Production Q Revenue (1) Q Operating Netback (1) 9% 20% 12% 16% 48% 44% 75% 32% 44% Est. Q Production Est. Q4 Revenue (1) Est. Q4 Operating Netback (1) 2% 9% 9% 72% 19% 19% increase in quarter over quarter condensate & NGL production weighting 65% 26% U.S. market diversity increases natural gas netback contribution by 50% 66% 32% (1) Includes realized hedging gains and losses in the period Natural Gas Light & Heavy Oil Condensate & NGL 17

18 Flare volume % of Plant Inlet Flare volume/well (10 3 m 3 ) ENVIRONMENTAL LEADERSHIP IS A PRIORITY Recycled Water Used for Hydraulic Fracturing (%) Hazardous Waste Recycling Avg Per Year ( ) 100 >95% % 67% 61% 72 AB Tonnes 19 Of waste diverted from landfills BC 53 Tonnes Tonnes Gas Plant Flaring Performance 0.25% 0.21% 0.20% 0.18% 0.15% 0.15% 0.10% Continued year-overyear improvement in gas plant flaring performance with a two year 29% reduction Average Flare Volumes >85% Reduction due to inline testing Crew prioritizes testing wells inline to reduce flaring 0.05% %

19 KEY MONTNEY BUILDING BLOCKS ARE IN PLACE Massive Montney Resource Condensate, Light Oil & NGL Exposure Technological Applications to Reservoir are Evolving 16+ billion boe TPIIP(1) with 5,380 identified locations (1) on >282,000 net acres Only 13% of Upper Montney land has reserves assigned Focus on condensate-rich assets at West Septimus A 1,000 bbls/d condensate increase represents $20-25MM of funds flow (2) Continued evolution of geosteering, well spacing, frac design & reservoir depletion strategies Owned & Operated Infrastructure with Market Diversity Financial Flexibility & Ample Liquidity Infrastructure in place to support growth to >40,000 boe/d 83km of line pipe project ( 18) connecting Greater Septimus to Groundbirch & TCPL system Processing and transportation options to multiple markets Cost controls + market diversity + condensate focus = higher netbacks $300MM of debt termed out to 2024 & only 16% drawn (after netting off $11MM working capital surplus) on $235MM facility at Sept Capital structure aligned with long term plan (1) Identified locations are the total number of risked Contingent (1,841) and Prospective (3,160) resource locations identified in the Sproule Resource Report and the 2P booked undeveloped Montney locations (379) from the Sproule Reserve Report. See complete details on the Sproule Resource Report and Sproule Reserve Report in the presentation appendix (2) Price deck for funds flow forecast: C$1.60/GJ AECO, US$52.00 WTI, $0.76 F/X 19

20 Millions of barrels per day Billions of cubic metres IMPORTANCE OF CANADIAN ENERGY GLOBALLY Canada is the 4 th largest oil, liquids and gas producing country in the world Oil & Liquids Production (2017) Natural Gas Production (2017) US Saudi Arabia Russia Canada China Iran Iraq UAE Brazil Kuwait 0 US Russia Iran Canada Qatar China Norway Australia Saudi Arabia Algeria (1) Source: US Energy Information Administration (EIA) (2) Source:

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

22 APPENDIX

23 2019 CAPEX PROGRAM & FORECAST 2019 Cash Flow (CF) (mm) $ Net Capex (mm) $ Year-end net debt (mm) $342 Assumptions: Production guidance (boepd) 22,000-23,000 Pricing Gas (NYMEX US$/mmbtu) $3.30 Oil (WTI-US$/bbl) $52.00 WTI to WCS diff. 40% FX ($US/$CDN) $0.76 Interest rate-bank debt 4.5% Interest rate-high yield 6.5% Royalties 5-7% Op. costs ($/boe) $ Transportation ($/boe) $ G&A ($/boe) $ Hedging Summary as of February 15, 2019 Volume Period Derivative Reference Price Natural Gas 22,500 mmbtu/day 2019 Swap Chicago C$3.54/mmbtu 5,000 mmbtu/day 2019 Swap Dawn C$3.56/mmbtu 7,500 mmbtu/day 2019 Swap NYMEX US$2.98/mmbtu Oil 500 bopd Jan Jun 2019 Swap $C WCS / bbl C$ ,874 bopd 2019 Swap $C WTI / bbl C$ bopd Jul Dec 2019 Swap $WCS Differential C$(25.23) 250 bopd Jan Jun 2019 Swap $WCS Differential C$(25.75) 2019 Budget Sensitivities Input Change Cash Flow Impact (mm) CF / FD Share Impact ($/share) 100 bbls per day condensate $2.1 $0.01 CDN $1.00 per bbl WTI $1.5 $ mmcf per day natural gas $0.9 $0.01 $0.10 per mmbtu NYMEX $5.1 $0.03 $0.10 per GJ AECO 5A $0.8 $0.00 $0.01 FX CDN/US $2.9 $0.02 Interest Expense ($/boe) $

24 PROCESS AND TRANSPORTATION CAPACITY 275 mmcf/d takeaway capacity with 325 mmcf/d of processing PROCESSING 350,000 TRANSPORTATION 300,000 Groundbirch Facility (Proposed) 120 mmcf/d 250,000 West Septimus Facility 120 mmcf/d 200, , ,000 * TCPL/Nova 60 mmcf/d firm increasing to 120 mmcf/d (Jun 19) Spectra 30 mmcf/d firm Septimus Facility 60 mmcf/d Other 25 mmcf/d 50,000 0 Jan-18 Jul-18 Jan-19 Jul-19 Jan-20 Jul-20 Alliance 100 mmcf/d firm + 25 priority interruptible available Additional capacity post-2021 is available * on the TCPL / Nova System 24

25 Natural Gas Prices ($C/MCF) POSITIVE 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 ~20% Higher heat content gas realizes premium to AECO benchmark $ - Nov-15 Dec-15 Q Q Q Q Q Q Q Q Q Q Q (1) Crew Realized Price Chicago City Gate at ATP AECO 5A ATP (CREC) Station 2 (1) Wellhead price before impact of hedging 25

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. Sproule Reserve Report is the independent reserves evaluation for the year ended December 31, 2018 prepared by Sproule Associates Limited in accordance with the COGE Handbook provisions and NI Sproule Resource Report is the independent resource evaluation for the year ended December 31, 2016 prepared by Sproule Associates Limited in accordance with the COGE Handbook provisions and NI 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. 26

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, 2018 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 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". Non-IFRS Measures and FOFI - References are made in this presentation to "operating netback" or "netback", and funds from operations" which are not generally accepted accounting measures under IFRS and do not have any standardized meaning prescribed by IFRS and, therefore, may not be comparable with definitions of such terms that may be used by other public companies. Non-IFRS measures should not be considered in isolation or as a substitute for measures prepared in accordance with IFRS. This presentation contains future oriented financial information ("FOFI") within the meaning of applicable securities laws. The FOFI has been prepared by Crew's management to provide an outlook of the Company's activities and results. The FOFI has been prepared based on a number of assumptions including the assumptions discussed under the heading "Forward-Looking Information and Statements". Management does not have firm commitments for all of the costs, expenditures, prices or other financial assumptions used to prepare the FOFI or assurance that such operating results will be achieved and, accordingly, the complete financial effects of all of those costs, expenditures, prices and operating results are not objectively determinable. The actual results of operations of the Company and the resulting financial results may vary from the amounts set forth in this presentation, and such variation may 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 2018 annual production averaged 23,885 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 ( IP ) 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. 27

28 INFORMATION ON RESERVES, RESOURCES & OPERATIONAL INFORMATION Resource estimates within this Presentation are based upon the Sproule Resource Report. This evaluation was not updated since that date as changes were expected to be immaterial. 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 8, 2017 for a discussion of the principal risks, uncertainties and contingencies associated with the recovery and development of the Resource estimates presented herein. Certain information in this presentation may constitute "analogous information" as defined in NI , including but not limited to, information relating to the areas in geographical proximity to lands that are or may be held by Crew. Such information has been obtained from government sources, regulatory agencies or other industry participants. Crew believes the information is relevant as it helps to define the reservoir characteristics in which Crew holds an interest. Crew is unable to confirm that the analogous information was prepared by a qualified reserves evaluator or auditor. There is no certainty that the reservoir data and economics information for the lands held by Crew will be similar to the analogous information presented herein. Inputs for Rate of Return & Payout Calculations for W. Septimus: Ultra Condensate Rich Slide West Septimus Transition Ultra Condensate Rich DCET Capital ($MM) Month IP (boe/d) 1,050 1,350 1,245 Condensate (1) (%) Reserves (mboe) 967 1,323 1,093 Condensate (1) (%) (1) Condensate referenced above excludes plant recoveries. 28

29 NE BC MONTNEY RESOURCE EVALUATION Dec. 31, 2016 Dec. 31, 2015 Conventional Natural Gas Resource Categories (1)(2)(3)(4) )(5)(6) Tcf Tcf % Total Petroleum Initially In Place (TPIIP) Discovered Petroleum Initially In Place (DPIIP) Undiscovered Petroleum Initially In Place (UPIIP) (1) TPIIP, DPIIP and UPIIP have been estimated using a one percent porosity cut-off in the Resource Evaluation, 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. (5) There is uncertainty that it will be commercially viable to produce any portion of the resources. (6) There is no certainty that any portion the resources will be discovered. If discovered, there is no certainty that it will be commercially viable to produce any portion of the resources. Dec. 31, 2016 Dec. 31, 2015 Light & Medium Crude Oil Resource Categories (1)(2)(3)(4)(5)(6)(7) Mmbbls Mmbbls % Total Petroleum Initially In Place (TPIIP) Discovered Petroleum Initially In Place (DPIIP) Undiscovered Petroleum Initially In Place (UPIIP) 7,979 1,647 6,332 7,895 1,613 6,282 (1) TPIIP, DPIIP and UPIIP have been estimated using a one percent porosity cut-off in the Resource Evaluation, 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. (6) There is uncertainty that it will be commercially viable to produce any portion of the resources. (7) There is no certainty that any portion the resources will be discovered. If discovered, there is no certainty that it will be commercially viable to produce any portion of the resources. 0% 0% 0% 1% 2% 1% 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% 89% 80% Best Estimate Unrisked 1,426 8, Best Estimate Risked 1,426 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. Reserves and development pending volumes include 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, 125 bcf of conventional natural gas, 2 mmbbls of NGLs and 3 mmbbls of light and medium crude oil

30 NE BC MONTNEY RESOURCE EVALUATION CONT D 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) 66% 66% 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 any portion of the resources will be discovered. If discovered, 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. 30