CANBRIAM ENERGY INC. CORPORATE PRESENTATION JANUARY 2019

Transcription

1 CANBRIAM ENERGY INC. CORPORATE PRESENTATION JANUARY 2019

2 Canbriam Energy: Established, Experienced and Differentiated An integrated, BC Montney liquids rich natural gas growth company with differentiated resource quality Established premier position based on the management team s collective technical and subsurface expertise 100% working interest and operatorship in core Altares & Kobes Montney lands Kobes Fort St. John 300 m 350 m of net pay thickness on ~171,000 net acres (~60% of acreage is within liquids rich window) Altares High EURs in the primary Altares development area, with total liquids yields between bbls/mmcf Williston Lake Fort St John Scalable processing facilities are 100% owned and operated Long-term access to water: 20-year permit to withdraw 10,000 m 3 per day from Williston Lake <100% working interest 100% working interest Natural gas processing plant Groundbirch 15 km Enbridge T North 2007 Founded Q Commissioned initial gas processing facility Canbriam Energy Timeline Q Acquired Suncor Energy Montney land position Q Received initial private equity funding 2015 Commissioned Phases 1 & 2 of b-72-a facility and water infrastructure 2

3 Investing in Canbriam Energy Canbriam s integrated approach supports low cost Montney development & full cycle value creation Prolific BC Montney asset with low risk development inventory Integrated strategy provides low operating cost & flexibility Focus on low cost structure and full cycle profitability Experienced management with top-tier sponsorship 3

4 Canbriam s Altares is located in the prolific B.C. Montney The BC Montney has significant well density and peer activity Canbriam Energy Williston Lake 15 km 4

5 Positioned within the liquids rich fairway of the BC Montney Large, contiguous land position in Altares & Kobes supports liquids rich natural gas development Dry gas Rich gas bbl/mm Oil window 100+ bbl/mm Strong liquids component Q3 2018: 15% liquids yield by volume Kobes Condensate receives advantaged pricing in Western Canada due to its use in heavy oil blending Plant temperature can be modified to adjust propane yield dependent on NGL pricing Altares Canbriam Montney acreage Region Gross acres Net acres Altares / Kobes 174, ,693 Groundbirch 16,445 9,743 Total 190, ,436 Canbriam 100% working interest Canbriam 65-75% working interest 5 Source: Canbriam. Existing Montney well locations shown.

6 Mboe/d Stable production history with strong liquids content Canbriam s production growth is supported by the phased expansion of the Altares Processing Facility 45 Altares Sales Production history (Mboe/d) Natural gas (sales gas) Total Liquids Nameplate capacity (Boe/d) Oct 2015: Phase 2 of Altares Processing Facility (+80 MMcf/d) Q318: planned downtime (2) 25 Feb 2015: Phase 1 of Altares Processing Facility (80 MMcf/d ) 20 b-24-h plant outage (1) May 2012: Commissioned 50 MMcf/d b-24-h facility Natural gas 5 Liquids 0 (1) On May 18, 2017 the 50 MMcf/d b-24-h facility experienced an isolated fire and was brought back online on December 11, (2) During Q the company completed 5 new wells resulting in planned downtime to production levels. 6

7 Mboe/d Enbridge incident on T South pipeline Financial impact to Canbriam mitigated by risk management Enbridge T South incident on October 9, 2018 T South sales pipeline capacity reduced due to incident 36 line (repaired) and 30 line remains operational at combined reduced rates of ~0.9 Bcf/d Enbridge expected to increase to full operating capability upon regulatory review Updated full year production guidance reflects Q4 voluntary curtailment to ~26,000 boe/d: Updated: 34,000 35,000 boe/d Previously: 37,000 39,000 boe/d Prudently managing Q price exposure: Minimized Station 2 spot exposure with voluntary production curtailment; preferentially producing high liquid content wells Fully hedged at 26,000 boe/d production (or ~160,000 GJ/d): Financial & Physical fixed price hedges: ~148,000 GJ/d at average C$2.68 Physical basis: 11,000 GJ/d at average Sumas less US$ Natural gas Liquids Canbriam Sales Production history (Mboe/d) Q318: planned shut-ins for summer completion program T South incident Production voluntarily curtailed to ~26,000 boe/d 0 May-18 Jun-18 Jul-18 Aug-18 Sep-18 Oct-18 Nov-18 Dec-18 7

8 Convergence of key parameters in Altares & Kobes Canbriam acquired its position in Altares in 2008 after an extensive regional Montney review Thick Reservoir (300+ m) Highly Over-Pressured ( x) Free Liquids ( bbl/mmcf) Total Montney Isopach (meters) Pressure gradient (kpa/meter) Dry gas Rich gas bbl/mm Oil window 100+ bbl/mm meters of net pay thickness has resulted in 5 commercial layers of development Structural history of the reservoir has led to compartmentalization and regional faulting which requires integrated subsurface approach Highly overpressured, leading to high resource density ( Bcf/section) and very strong well productivity Burial history and thermal maturity have resulted in strong liquids content Initial free condensate yields in the Altares asset range from bbl/mmcf 8

9 Gas Rate in 24th Month of Production (mmcf/d) BOE/D Gas Rate in 12th Month of Production (mmcf/d) High Well Productivity & Low Decline Base Production Asset quality has supported top-tier performance and lower base declines 12-month Rate vs. 12-month Cumulative Production (Q3 2018) Production by Well Vintage Northern Montney wells Canbriam MFB Average months of cumulative production (bcf) 40,000 35,000 30,000 25,000 20, H Exploratory 25% corporate decline rate (1) 24-month Rate vs. 24-month Cumulative Production (Q3 2018) 6 5 Northern Montney wells Canbriam MFB Average 15,000 10, , months of cumulative production (bcf) 9 Source: GeoScout (1) Calculated by McDaniel & Associates as Proved + Proved Developed Producing (P50 best estimate) forecast decline of 25.3% for 2017 reserves report.

10 Completed Length (meters) Increased drilling & completion efficiency in over-pressured Montney Canbriam s Altares drilling requires underbalanced drilling with mud weights exceeding 1,800 kg/m 3 Unique challenges in over-pressured Doig & Montney formations Improved well design & longer reach laterals have improved drilling & completion efficiency We anticipate longer lateral well lengths with the additional Suncor land Completion efficiency (lateral completion length in meters) Drilling efficiency ($M/meter drilled) 3,500 3,000 Well Average Online Q $2.50 $2.00 Drill cost per meter of total measured depth 2,500 $1.50 2,000 $1.00 1,500 $0.50 1, $ Source: Canbriam 10

11 Canbriam s High Quality Altares Montney Footprint Ideally positioned in the liquids-rich window of the B.C. Montney Key reservoir attributes of the Altares Montney region meter thick reservoir with five commercial intervals Over-pressured by up to 2 times in Altares Rich gas boundary Pressure gradient > 18Kpa/m Subsurface compartmentalization Thickness > 300 m Canbriam land Strong liquids potential with up to 40 bbl/mmcf free condensate content Unique geological structure leads to distinct high pressure regions with consistent well results Reservoir Quality and Consistency of Results Supports Top Quartile Supply Costs versus Montney Peer Group (1) Montney Peer Companies 5-25 Peers 1-3 (1) Supply stack from RSEG July 17, 2018, Montney peer company names have been removed 11

12 Altares Processing Facility: scalable to 400 MMcf/d Canbriam owns & operates all of its processing infrastructure Water treatment & recycling hub Commissioned March 2015 Phase 4: 120 MMcf/d Sanctioning to be determined Phase 3: 120 MMcf/d Sanctioned Q4 2016: long lead items purchased Phase 2: 80 MMcf/d Commissioned September 2015 Phase 1: 80 MMcf/d Commissioned February 2015 August

13 Competitively advantaged in water sourcing, handling & disposal Integrated water strategy eliminates need to truck water Sourcing & distribution >80% water recycle rate (1) $0.23/boe operating expenses tied to water handling (2) 1 Bcf/d production supported by water strategy 3 year payback on total investment (3) 20 year permit (2011) to access 10,000 m 3 /day of fresh water from Williston Lake Water treatment & recycling Allows for continuous flow back while supplying treated water to other frac operations All pad locations pipeline connected for water Eliminates trucking of fresh, flowback & produced water providing benefits to stakeholders Disposal Second disposal well commissioned in Q Passive seismic monitoring in place Provides water takeaway flexibility during periods of lower activity (1) Based on 2018 water balances forecast. Recycle rates generally increase with activity levels as disposal requirements decrease. (2) 2017 actual operating expenses related to water. Comparative water related operating expenses in were $1.25/boe, $0.74/boe and $0.27/boe, respectively. (3) Based on $76MM total capital investment to date and actual capital & operating cost savings over a two rig, 24 wells per year development pace. 13

14 Marketing & transportation plan supports long term development Sufficient takeaway capacity to support near term requirements MMcf/d Enbridge T North: 228 MMcf/d firm capacity Incremental 20 MMcf/d added effective April 2019 Variable term, scalable with production growth Potential future transportation options Enbridge T North firm capacity TCPL North Montney: 107 MMcf/d firm (Apr 2019E) Canbriam s firm transportation capacity Enbridge T North Birch Block valve site Liquids pipeline (completed Q4 2017) TCPL North Montney (expected) ENB T North North Montney 107 MMcf/d <100% working interest 100% working interest Natural gas processing plant Water handling & recycling hub MMcf/d T North: 228 MMcf/d Variable term & scalable Williston Lake Water pipeline TCPL North Montney (under construction) 0 Jan-14 Jan-15 Jan-16 Jan-17 Jan-18 Jan-19 14

15 Price realizations benefit from liquids content, hedging & heat content Disciplined risk management & active hedging program have supported realized prices $30.00 Revenue by product: 2015 Q ($/boe) $3.50 High heat content natural gas (1) $25.00 $20.00 $15.00 $10.00 $5.00 Realizations: $0.00 NGL Condensate Natural Gas $21.78 $21.51 $21.68 $21.15 $21.14 $15.88 $15.42 $16.83 $4.88 $16.24 $16.66 $1.30 $2.52 $1.54 $16.42 $15.78 $4.03 $6.35 $5.33 $3.74 $4.46 $5.20 $3.32 $4.57 $10.54 $10.17 $10.11 $9.94 $6.02 $8.00 $17.39 $20.50 $33.64 $48.15 $50.64 $49.05 $53.80 $49.82 $59.46 $76.67 $83.98 $77.88 $2.07 $2.00 $1.98 $2.03 $1.19 $ Q Q Q $3.00 $2.50 $2.00 $1.50 $1.00 $0.50 $ % premium due to heat content Station 2 ($/mcf) Realized price (includes heat content premium & physical sales gains) ($/mcf) Q2 Q3 Q4 Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 Q1 Q2 Q Production Production (%) Revenue (%) Q Pricing (% Edm Par) Production Production (%) Revenue (%) Pricing (% Edm Par) Natural gas (MMcf/d) % 48% % 60% - Condensate (bbl/d) 1,419 4% 20% 95% 1,691 6% 23% 94% Natural gas liquids (2) (bbl/d) 3,610 11% 32% 60% 2,196 8% 17% 54% Total (boe/d) 33, % 100% - 26, % 100% - (1) High heat content due to ethane left in natural gas sales stream. (2) Natural gas liquids include Pentanes plus production. 15

16 $/boe Low cost structure supports full cycle profitability Canbriam s low cost structure drives strong play economics despite low commodity prices Canbriam Cost Structure vs. Price Realizations (2014 Q3 2018) $40 $35 $36.51 $35.88 $30 $25 $21.48 $21.39 $21.38 $21.15 Blended price realization before hedging (15% liquids) C$2.25 Station 2; US$60 WTI $20 $15 $10 $5 $0 $9.48 $21.14 $9.03 $16.27 $16.24 $15.51 $15.36 $7.37 $7.17 $15.78 $1.95 $8.28 $7.18 $3.34 $6.81 $4.93 $5.02 $3.51 $1.97 $3.53 $0.75 $0.64 $0.79 $0.49 $2.22 $0.87 $4.19 $2.58 $2.15 $3.59 $3.42 $2.21 $1.46 $1.64 $1.22 $0.95 $3.41 $2.86 $2.27 $2.52 $1.97 $2.40 $16.66 $16.42 $6.07 $7.20 $4.08 $4.08 $0.49 $0.49 $3.59 $3.59 $1.09 $1.09 $3.32 $3.32 C$1.75 Station 2; US$60 WTI C$1.25 Station 2; US$60 WTI Capital costs (2) Finance costs Cash operating costs (1) Production (boe/d) , , , ,866 Q ,704 Q ,358 Q ,247 Q PDP F&D Operating G&A Transportation Royalties Finance costs PDP F&D DD&A Realized price (before hedging) Realized price (inc. hedging) Note: Full cycle includes all cash costs (operating, royalties, transportation, general & administrative, interest) plus depletion, depreciation and amortization on a per barrel of oil equivalent basis. (1) Effective November 1, 2017 transportation expense reflects the change in sales point from NEBC to Edmonton due to liquids pipeline. NGL & Condensate pricing expected to offset this increase in per unit transportation cost due to change in sales point from field locations to the Edmonton market. (2) Capital costs are shown as DD&A from Q as representation for the cost of adding infrastructure and related D&C; and PDP F&D from 2017 reserves ($6.07 per boe) the cost of D&C only to keep existing facilities full. 16 Canbriam Energy Corporate Presentation

17 Prudently managing 2018 price exposure Station 2 exposure eliminated in Q4 2018E through voluntary production curtailment Regional price exposure Q4 2018E on 40,000 boe/d capacity (~220,000 GJ/d) Voluntarily curtailed volumes ~60,000 GJ/d Sumas physical basis Sumas based physical contracts (1) 15% Physically contracted for 11,000 GJ/d at Sumas less US$0.74/MMBtu Fixed price hedges ~148,000 C$2.68 Fixed price hedges (2) 85% 148,000 GJ/d Natural gas protected at C$2.68/GJ (1) Canbriam has entered physical basis contracts for 2018E 2021E production. Custody transfer of the physical basis contracts takes place in British Columbia. Price points less basis as follows: SoCal: Border average NGI; Sumas: NWPL Canadian border IFERC (2) Fixed price hedges include financial hedges and physical sales contracts. 17

18 GJ/d Natural gas & liquids price risk management Active hedging, physical sales basis contracts & high heat content have optimized natural gas pricing Natural gas hedges (2) (at November 15, 2018) Liquids hedges (at November 15, 2018) 225, ,000 5,000 $68.32 $68.60 $71.08 $80 $70 175,000 4,000 $60 150, , ,000 75,000 50,000 25,000 $1.88 $1.47 $1.47 $1.47 3,000 2,000 1,000 3,750 3,100 1,300 $50 $40 $30 $20 $10 0 Q1 Q2 Q3 Q Fixed Price ($/GJ) Sumas Basis (US$/mmbtu) SoCal Border Basis (US$/mmbtu) SoCal City Basis (US$/mmbtu) Volume hedged (bbls/d) WTI weighted average price (C$/bbl) $0 NYMEX Basis (US$/mmbtu) AECO Basis ($/GJ) Weighted average fixed price ($/GJ) (1) High heat content due to ethane in natural gas stream. (2) Floating (Basis) gas hedges include physical sales contracts with fixed differentials to pricing hubs at SoCal, Sumas, Chicago & AECO and Financial basis swaps at AECO & Sumas. Weighted average fixed price shown. 18

19 Investing in Canbriam Energy Canbriam s integrated approach supports low cost Montney development & full cycle value creation Prolific Montney resource with low risk development inventory 100% working interest and operatorship in core Altares & Kobes Montney lands ~1,100 of Montney vertical thickness on ~183,000 (>60% liquids rich) net acres MMboe of gross 1P Reserves (PV 10 of $1,662 MM) (1) & MMboe of gross 2P Reserves (PV 10 of $2,490 MM) (1) Over pressured reservoir (up to 2x) and use of down-hole chokes limits declines, optimizes liquids and growth High EURs in the primary Altares development area, with liquid yields between bbls/mmcf Integrated strategy provides low operating cost & flexibility Scalable processing facilities are 100% owned & operated; brownfield expansions support efficient growth Team approach fosters culture of collaboration, safety & high performance Prudent approach to financial management supports solid financial position Focus on low cost structure and full cycle returns 100%-owned gathering and processing facilities support controlled development pace & low cost structure Long term access to water: 20 year permit to withdraw 10,000 m 3 per day from Williston Lake Favorable regulatory regime, scalable firm marketing arrangements & close proximity to gas sales pipeline Experienced management with top tier sponsorship Management team averages 25+ years of industry experience with prominent E&P companies Team was built specifically to be able to find and develop differentiated areas within unconventional fairways Experienced E&P sponsors including Warburg Pincus, ARC, OTPP, State Street, BlackRock Recent equity financing (June 2017) & Suncor transaction represent strong votes of confidence (1) Based on McDaniel & Associates reserves report as of December 31, PV10 amounts quoted on a before tax basis. (2) Pricing assumptions: US$3.00/MMbtu NYMEX; US$50.00/bbl WTI; 0.75 US$/C$ exchange rate. See type curve economics. 19

20 SUPPLEMENTAL INFORMATION 20

21 Canbriam has the foundation for long term value creation Our approach is defined by three key elements Resource Innovation Collaboration Montney is a world class reservoir Altares has unique geological attributes that make it among the lowest supply cost resource within the Montney Canbriam s success is tied to early quality differentiation within the Altares Montney Long-term approach to water sourcing, handling & recycling supports scalable resource development for decades Team approach fosters culture of collaboration, safety & high performance Geology, geophysics & reservoir engineering integrated with drilling & completions in real time High degree of control & scalable design supports full scale development 21

22 Canbriam Energy leadership Team built specifically for exploration & development of unconventional gas resource Paul Myers President and Chief Executive Officer Founder and CEO since company inception in 2007 Diverse 30 year career in various leadership roles for Amoco, Statoil & PanCanadian/Encana Track record of organic value creation in unconventional resource development and deep water Gulf of Mexico Larry Cole Chief Financial Officer Responsible for all finance, accounting and risk management functions at Canbriam Prior to being appointed CFO in January 2019, Larry was Vice President Finance at Canbriam and joined the company in 2007 as Controller Track record of financial leadership roles at Pengrowth Energy Trust and PricewaterhouseCoopers Graham Janega Chief Operating Officer Appointed COO in January 2019, Graham leads all operating and subsurface functions at Canbriam Joined Canbriam in 2013 as Drilling & Completions Engineer and was appointed Completions Manager in March 2015 prior to moving into the Vice President Subsurface role in January Prior to Canbriam, Graham s career includes operational roles at Pengrowth Energy and Shell Canada Donna Phillips Executive Vice President, Corporate Development Responsible for External Engagement, Land and Corporate Development at Canbriam Formerly Vice President, Land at Direct Energy/Centrica Canada Ltd. Donna began her oil and gas career in finance at SaskOil, following which she pursued opportunities to work in corporate planning and asset management at Wascana Energy and land group roles at Nexen Nauman Rasheed Vice President, Operations Extensive experience in Facilities, Operations and Health, Safety & Environment leadership, Nauman is responsible for all Drilling & Completions, Facilities and Production related functions at Canbriam Joined Canbriam in 2012 as Vice President, Facilities & Production from Pengrowth Energy Corp. where he held various operational leadership roles 22

23 F&D ($/boe) Recycle ratio Significant reserves growth with high liquids content Canbriam s 2P bookings reflect consistent well performance 2P Reserve growth (MMboe) Gas Liquids $25 $20 $15 $10 $5 $0 2P F&D costs & recycle ratio (1) $21.00 $12.00 $11.50 $12.00 $7.68 $8.00 $5.31 nmf $ F&D Recycle ratio Summary of gross reserves as of Dec 31, 2017 (2) Category Natural Gas (Bcf) NGLs (MMbbls) Total (MMboe) Total (%) PV 10% ($MM) (3) Net Locations Proved Developed % $ Proved Undeveloped % $ Total Proved 1, % $1, Probable % $ Total Proved + Probable 2, % $2, (1) Recycle ratio defined as operating netback including hedging gains/losses divided by 2P Finding & Development costs. Negative F&D in 2016 due to 16% reduction in Future Development Costs and therefore recycle ratio and 2P F&D costs were negative. (2) Reserves are prepared by McDaniel & Associates and are calculated on a gross company interest basis, before royalties and based on an 8 year development plan. Categories may not total due to rounding. (3) Before tax and based on McDaniel & Associates pricing as of 1/1/18. Future development capital (FDC) reduced by 2% to $1.68 Billion. 23

24 Illustrative type curve economics Main Fault Block type well statistics represent the current planning basis for Canbriam Single well statistics Main Fault Block Well properties Upper Montney Lower Montney Raw gas type curve (Bcf) (1) Sales gas (Bcf) (2) Liquids (Mbbl) (1) EUR/well (total - Bcfe) % liquids (of total EUR) (1) 17% 10% Initial liquids yield (bbls/mmcf) Horizontal well length (3) (meters) 2,000 2,000 Well economics Drilling, completion & tie-in/equipment costs ($MM) $7.0 $7.0 Operating & transportation costs (4) ($/boe) $5.80 $ % 120% 100% 80% 60% 40% 20% 0% $15.0 $10.0 $5.0 $- BT IRR (%) $1.00 $1.50 $2.00 $2.50 $3.00 $3.50 Station 2 ($/GJ) Upper Montney - 9BCF, $7MM DCET Lower Montney - 8BCF, $7MM DCET BT NPV 10 ($MM) 24 Average royalty rate (5) 10% 8% (1) Type curve and liquid yields (free condensate & plant liquids) represents current planning basis for Canbriam. (2) Assumes shrinkage of 6%. (3) Well lengths have increased steadily since 2015 and with the addition of Suncor lands, the company expects to consistently drill ~3,000 meter or longer well lengths which should have a positive impact on per well EURs over time (4) Operating costs include all well costs and fixed plant costs. Transportation costs are ~$2.10/boe. (5) Crown royalty rate is 3% minimum until royalty credit of $2.5 MM per well is paid out, then 27% (natural gas) and 20% (liquids) thereafter. Royalty includes BC government cost allowance and excludes average gross overriding royalty of 2.5% within the Main Fault Block. Assumes lateral (horizontal) well length of 2,000 m. Royalty rates are calculated on a before-tax basis using flat pricing assumptions: US$3.00/MMbtu Nymex; US$60.00/bbl WTI; C$2.37/GJ AECO; C$2.02/GJ Station 2; 0.80 US$/C$ exchange rate. D&C costs reflect additional $200 M per well tied to pad cost allocation for leasehold construction. Well economics represent average of Upper Montney wells that we expect to drill within the current five year plan. $(5.0) $1.00 $1.50 $2.00 $2.50 $3.00 $3.50 Station 2 ($/GJ) Upper Montney - 9BCF, $7MM DCET Lower Montney - 8BCF, $7MM DCET

25 Gas Rate (MMcf/d) Shut-in casing pressure (kpa) Optimizing well performance through choke management strategy Canbriam s use of downhole chokes optimizes its over-pressured reservoir Advantages of downhole chokes: Minimizes 1 st year declines and fosters stable production Enhances EUR by maintaining bottomhole pressure Prevents the formation of hydrates when starting up wells Protects surface pipe integrity through better sand management Jan 2014: upsized choke incremental 1.47 MMcf/d Altares c-b27-h well - Upper Montney May 2014: upsized choke incremental 2.38 MMcf/d Feb 23, 2016: Shut in for offsetting fracking operations Aug 15, 2016: Shut in for offsetting fracking operations 30,000 28,000 26,000 24,000 22,000 20,000 18,000 16,000 14, , , , , , , Cumulative-to-date: Mar 31, 2017 = 4.8 bcf 25

26 Lower Upper Development plan includes five commercial intervals Three Upper Montney & two Lower Montney layers at 300 meter spacing 7 Tested zones C5 Commercial Intervals1 & 2 C4 Commercial Interval 3 C2 T1 300 m 165 m / 550 feet Commercial Interval 4 T2 300 m 150 m / 500 feet Commercial Interval 5 T3 26

27 Evolution of Completion Optimization Completion efficiency improving through technology advancement & integrated technical approach Initial Development ( ) Development Phase ( ) Current Design ( ) Future Enhancements (2019+) Plug & perf (slickwater) tonne/meter proppant loading meter cluster spacing 8 14 stages per well Average horizontal length ~1,600 meters Main Fault Block 3 zones (2 Upper, 1 Lower) 200 meter well spacing 13 wells Plug & perf (slickwater) & Testing pinpoint sliding sleeve tonne/meter proppant loading meter cluster spacing stages per well Average horizontal length ~1,950 meters Main Fault Block 4 zones (2 Upper, 2 Lower) 200 meter well spacing 39 wells Pinpoint sliding sleeve tonne/meter proppant loading meter sleeve spacing sleeves per well Average horizontal length increasing Main Fault Block; Testing North & East Fault Blocks 5 zones (3 Upper, 2 Lower) 300 meter well spacing Parent/child well management Tailored completion design tonne/meter proppant loading 30 meter sleeve spacing 90+ sleeves per well Targeting 3,000+ meter horizontal lengths Main, North & East Fault Blocks all commercialized 5 zones (3 Upper, 2 Lower) 300 meter well spacing Parent/child well management Optimized frac water chemistry 27 Canbriam Energy Corporate Presentation

28 bbls/d Yield bbls/mmcf MMcf/d Stable production history with strong liquids content Canbriam s production growth reflects addition of phases 1 & 2 of the Altares Processing Facility in Inlet Sep Capacity 40,000 Boe/d nameplate capacity Natural gas production 30,000 Boe/d capacity (1) ,000 Boe/d nameplate capacity May-16: MP73 outage Sept-15: Plant turnaround Q217: Road bans & b-24-h outage (1) 0 Jan-15 Apr-15 Jul-15 Oct-15 Jan-16 Apr-16 Jul-16 Oct-16 Jan-17 Apr-17 Jul-17 Oct-17 Jan-18 Apr-18 Jul-18 Oct-18 8,000 7,000 Liquids production Q318: Planned downtime (2) , , , , , ,000 Q217: Road bans & 10 Sept-15: Plant turnaround b-24-h outage (1) 0 0 Jan-15 Apr-15 Jul-15 Oct-15 Jan-16 Apr-16 Jul-16 Oct-16 Jan-17 Apr-17 Jul-17 Oct-17 Jan-18 Apr-18 Jul-18 Oct Free Condensate Condensate Butane Propane Plant Yield (10 day average) (1) On May 18, 2017 the 50 MMcf/d b-24-h facility experienced an isolated fire was offline until December 11, During that period, effective production capacity was limited to 160 MMcf/d or 30,000 boe/d including liquids. (2) During Q3 2018, the company shut in [X] boe/d for ongoing completion programs.

29 Historical financial summary Financial performance reflects improving cost structure and production growth Average production (Mboe/d) Adjusted EBITDA (1) (C$ millions) $144 $ $66 $83 $88 $ Q YTD Q YTD Capital expenditures (2) (C$ millions) Total cash costs ($/boe) $365 $12.95 $314 $1.97 $116 $113 $147 $255 $109 $3.38 $8.04 $6.67 $7.38 $7.57 $7.26 $2.22 $4.19 $0.75 $2.24 $2.58 $3.59 $3.42 $2.21 $0.64 $0.64 $1.46 $1.64 $0.79 $0.49 $1.22 $0.95 $3.41 $2.86 $2.33 $2.52 $1.97 $2.40 $8.49 $3.59 $0.49 $1.09 $ Q YTD 2014 Production (boe/d) 9, , , ,866 Q ,704 Q ,358 Operating G&A Royalties Transportation Q ,247 (1) Includes risk management gains / losses. (2) Q capital expenditures includes $7.5 million transaction costs related to the Suncor Montney land acquisition, but excludes net proceeds from asset dispositions. 29

30 Historical netbacks Canbriam s low cash costs, liquids content and prudent risk management drive strong operating netbacks Benchmark prices Q3 Q2 Q1 Q4 Q3 Q2 Q1 Q4 Q3 Q2 Q1 Q4 Q3 Q2 Q1 Henry Hub (US$/MMbtu) AECO ($/mcf) (1) Station 2 ($/mcf) West Texas Int. (US$/bbl) Realized prices Natural gas ($/mcf) Condensate ($/bbl) NGLs ($/bbl) Netback ($/boe) Petroleum and natural gas sales Cash Royalties Operating expenses Transportation expenses Adjusted cash operating netback prior to risk management Realized risk management loss (gain) Adjusted cash operating netback after risk management (0.46) (0.01) (7.62) (7.46) (3.17) (1.14) (2.30) (5.40) (8.02) (8.63) (6.60) (6.49) (5.02) (5.46) (1) Effective Q1 2016, Canbriam reports AECO (7A month ahead) benchmark price; prior to 2016, Canbriam reported AECO (5A daily) benchmark price. AECO and Station 2 benchmark price converted to mcf on the basis of 1 mcf = GJ. 30

31 Supplemental reserves information 2017 Independent reserves evaluation completed by McDaniel & Associates Reserves Reconciliation (1) Proved Probable Proved + Probable Natural Gas NGLs Total Natural Gas NGLs Total Natural Gas NGLs Total Bcf MMbbls MMboe Bcf MMbbls MMboe Bcf MMbbls MMboe December 31, , , Technical revisions Technical revisions (64.2) (2.8) (13.5) Category change (10.0) (0.3) (2.0) (1.3) (0.0) (0.3) Extensions & Improved Recovery Production (50.3) (1.4) (9.8) (50.3) (1.4) (9.8) December 31, , , Summary of Future Development Costs (2) Proved (MM) Probable (MM) Proved + Probable (MM) December 31, 2016 $1,275 $444 $1,719 Changes ($46) $11 ($35) December 31, 2017 $1,229 $455 $1,684 (1) Reserves are calculated on a gross company interest basis, before royalties and based on an 8 year development plan. Categories may not total due to rounding. (2) Undiscounted, as calculated by McDaniel & Associates as of 12/31/17 based on an 8 year development plan 31

32 Forward looking information Certain statements included in this presentation constitute forward looking statements or forward looking information under securities legislation. Such forward looking statements or information are provided for the purpose of providing information about management's current expectations and plans relating to the future. Readers are cautioned that reliance on such information may not be appropriate for other purposes, such as making investment decisions. Forward looking statements or information typically contain words such as "anticipate", "believe", "expect", "plan", "intend", "estimate", "propose", "project" or similar words suggesting future outcomes or statements regarding an outlook. Forward looking statements or information concerning Canbriam in this presentation may include, but are not limited to, statements or information with respect to: future production levels and the expected timing for the achievement thereof; business strategy and objectives; expected resource potential and future reserves; development and exploration plans and the timing and results thereof; the development of and access to pipelines; type curves, including expected costs per well, well economics, EUR per well; potential expansion of Canbriam s natural gas processing facilities; anticipated cost structure, drilling activities and liquids yield; inventory of drilling locations; and expected timing and benefits of acquisitions. Forward looking statements or information are based on a number of factors and assumptions which have been used to develop such statements and information but which may prove to be incorrect. Canbriam believes that the expectations reflected in such forward looking statements or information are reasonable; however, undue reliance should not be placed on forward looking statements because Canbriam can give no assurance that such expectations will prove to be correct. In addition to other factors and assumptions which may be identified in this presentation, assumptions have been made regarding, among other things: the impact of increasing competition; the timely receipt of any required regulatory approvals; the ability of Canbriam to obtain qualified staff, equipment and services in a timely and cost efficient manner; the ability of Canbriam to obtain financing on acceptable terms; field production rates and decline rates; the ability to replace and expand reserves through acquisition, development or exploration; the timing and costs of operating Canbriam s business; the ability of Canbriam to secure adequate product transportation, including access to pipelines; future oil and natural gas prices; currency, exchange and interest rates; the regulatory framework regarding royalties, taxes and environmental matters; and the ability of Canbriam to successfully market its oil and natural gas products. Readers are cautioned that the foregoing list is not exhaustive of all factors and assumptions which have been used. Forward looking statements or information are based on current expectations, estimates and projections that involve a number of risks and uncertainties which could cause actual results to differ materially from those anticipated by Canbriam and described in the forward looking statements or information. These risks and uncertainties may cause actual results to differ materially from the forward looking statements or information. The material risk factors affecting Canbriam include, without limitation, the accuracy of reserves and resources estimates; reliance on key personnel; general economic conditions; volatility in global market prices for oil and natural gas; competition; liabilities and risks, including environmental liability and risks, inherent in oil and gas operations; the availability of capital; alternatives to and changing demand for petroleum products; changes in legislation and the regulatory environment, including uncertainties with respect to environmental legislation; title defects which may adversely affect Canbriam; the availability of drilling and related equipment in the particular areas where such activities will be conducted; constraints related to product transportation; relationships with First Nations in areas in which Canbriam operates; Canbriam's dependence on third parties; and other known or unknown factors. The forward looking statements or information contained in this presentation are made as of the date hereof and Canbriam undertakes no obligation to update publicly or revise any forward looking statements or information, whether as a result of new information, future events or otherwise unless required by applicable securities laws. The forward looking statements or information contained in this presentation are expressly qualified by this cautionary statement. 32

33 Reserves disclosure The reserve information herein represents estimates prepared by McDaniel & Associates Consultants Ltd. ( McDaniel ) with respect to Canbriam s natural gas and NGLs properties as of December 31, 2016 (the McDaniel Report ). The reserve estimates and related estimates of net present values presented in this presentation were prepared in compliance with Canadian disclosure standards and definitions as set out in National Instrument Standards of Disclosure for Oil and Gas Activities issued by the Canadian Securities Administrators ( NI ) and the Canadian Oil and Gas Evaluation Handbook ( COGE Handbook ) prepared jointly by The Society of Petroleum Evaluation Engineers and the Canadian Institute of Mining, Metallurgy & Petroleum. The disclosure standards under NI and the COGE Handbook differ from those applicable to U.S. reporting companies that prepare their reserves estimates in accordance with SEC requirements, including that reserves may be presented on a gross (before royalties) basis and all estimates of reserves and related estimates of net present values are prepared based on forecast prices and costs. This presentation contains the term estimated ultimate recovery or EUR from Canbriam s anticipated drilling locations. Canbriam uses the term EUR to mean those quantities of petroleum that are estimated, on a given date, to be potentially recoverable from an accumulation plus those quantities already produced. The EURs shown in this presentation have not been independently evaluated, audited or reviewed and are based on what management consider to be typical well production and recovery profiles applicable to the wells to be drilled on Canbriam s properties. This presentation contains the measure of internal rates of return or IRR. The EURs and IRRs disclosed in this presentation are based on estimates and assumptions of management based on independent evaluations, historical data, 44 Upper Montney and 14 Lower Montney development wells on production as of June 30, 2017, extrapolations therefrom and management s professional judgement, which involves a high degree of subjectivity. For these reasons, actual IRRs and EURs attributable to any particular group of Canbriam s properties may differ from the estimates herein and the differences could be significant. Disclosure of NPV10 in this presentation refer to the net present value of the future net revenues associated with Canbriam s natural gas and NGLs reserves determined in accordance with NI , before deducting income taxes and discounted at 10 percent, based on McDaniel s publicly available forecast pricing and cost assumptions as of January 1, McDaniel has identified approximately 188 net drilling locations on Canbriam s properties (proved undeveloped and probable, excluding 83 net proved developed wells and Canbriam s management has identified approximately 470 more economic net locations. McDaniel s drilling locations are based on a three rig development case, two geological target zone, and a smaller development area. Management uses a four rig development plan, three target zones, and a larger development area. Canbriam s ability to drill and develop these locations depends on a number of uncertainties, including, but not limited to, the availability of capital, equipment and personnel, oil, natural gas and NGLs prices, inclement weather, capital and operating costs, drilling results and production rate, recovery, success ratio, gathering system and transportation constraints, net price received for the commodities produced and regulatory and royalty changes. As a result of these uncertainties, there can be no assurance that the numerous potential drilling locations Canbriam has identified will ever be drilled or, if drilled, will be able to produce natural gas and NGLs from these or any other potential drilling locations. As such, Canbriam s actual drilling activities may materially differ from those presently identified, which could adversely affect Canbriam s business. In addition, we use the term de-risked to refer to drilling locations where we believe the geological risks related to recovery have been reduced as a result of drilling operations to date; however, our ultimate recoveries from such drilling locations remain subject to a number of risks. This presentation presents certain production and reserves-related information on an equivalency basis. Equivalent volumes are computed with oil and NGLs quantities converted to Mcfe at a ratio of one bbl to six Mcfe and natural gas converted to boe at a ratio of six Mcf to one boe. These conversions are based on energy equivalency conversion methods primarily applicable at the burner tip and do not represent value equivalencies at the wellhead. Given that the value ratio based on the current price of crude oil as compared to natural gas is significantly different from the energy equivalency of 6:1, utilizing a conversion on a 6:1 basis may be misleading as an indication of value. 33

34 Non-IFRS Measures This presentation includes certain terms or performance measures commonly used in the oil and gas industry that are not defined under IFRS, including netback, return on capital employed and adjusted EBITDA. Non-IFRS may not be comparable to similarly titled measures presented by other companies. The data presented is intended to provide additional information and should not be considered in isolation or as a substitute for measures of performance prepared in accordance with IFRS. Netback is a financial measure not presented in accordance with IFRS and is calculated on a per boe basis as natural gas and NGL sales, less royalties and operating and transportation expenses. The adjusted cash operating netback prior to risk management is calculated on a per boe basis as natural gas and NGL sales, less cash royalties, and operating and adjusted transportation expenses. The adjusted cash operating netback after risk management is calculated on a per boe basis as the adjusted cash operating netback prior to risk management plus realized risk management gains/losses. Netback and adjusted cash operating netback are used by management to measure operating results on a per boe basis to better analyze performance against prior periods on a comparable basis. Return on capital employed ( ROCE ) is calculated as EBIT/tangible capital employed. EBIT is earnings before interest, taxes, unrealized gains/losses from risk management and other capital related charges. Tangible capital employed is calculated as adjusted net working capital plus net fixed assets. Management uses ROCE to measure Canbriam s profitability and the efficiency with which its capital is employed. Recycle ratio is defined as operating netback divided by proved plus probable finding and development costs. Finding and development costs are capital costs incurred in the acquisition, exploitation and exploration of proved oil and natural gas reserves divided by proved reserve additions and revisions to proved reserves. Management uses the recycle ratio to measure Canbriam s profitability. Adjusted EBITDA is a financial measure not presented in accordance with IFRS and is equal to net income (loss) and comprehensive income (loss) before deferred income tax expenses/recoveries, depreciation and depletion expenses, finance costs, impairment, revaluation of preferred shares, share based compensation, unrealized risk management gains/losses, realized risk management gains/losses and royalty credits utilized. Adjusted EBITDA is not a measure of operating performance or liquidity under IFRS. Certain items excluded from adjusted EBITDA are significant components in understanding and assessing a company s financial performance, such as a company s cost of capital and tax structure, as well as historic costs of depreciable assets. Viewing adjusted EBITDA as an indicator of Canbriam s operating performance should be done with caution. 34

35 Canbriam Energy Inc. 2100, nd Street SW Calgary, AB Canada T2P 1M4 Tel: Paul Myers President & Chief Executive Officer pmyers@canbriam.com Larry Cole Chief Financial Officer lcole@canbriam.com Bill Stait Vice President, Capital Markets and Corporate M&A bstait@canbriam.com Copyright 2015 Canbriam Energy Inc. All rights reserved.