CANBRIAM ENERGY INC. CORPORATE PRESENTATION NOVEMBER 2017

Transcription

1 CANBRIAM ENERGY INC. CORPORATE PRESENTATION NOVEMBER 2017

2 Canbriam Energy An integrated, BC Montney natural gas growth company with differentiated resource quality Private company focused in the Altares region of the prolific Montney formation in northeast BC Montney trend 100% owned & operated processing infrastructure; production capacity currently 40,000 boe/d North Altares Fort St. John 2017 capital budget: $250 - $270 million Edmonton C$100 million private equity raise completed on June 30, 2017 on a pro-rata basis from existing sponsors Deep inventory of over-pressured, liquids-rich locations with stable, low-decline production base b-24-h Refrig Facility 50 mmcf/d Altares Processing Facility (b-72-a Refrig Facility 160 mmcf/d phases 1 & 2) Vancouver Calgary 366 MMboe gross 2P reserves (pre-tax PV10 of $2.6 billion) (1) Backed by top-tier sponsors Warburg Pincus, ARC Financial, OTPP, State Street Advisors & BlackRock Enbridge T North Dehy & compression Facility 10 mmcf/d 65-70% working interest 100% working interest Non-Montney lands Natural gas processing plant Enbridge T North 2 miles South Altares 2 (1) Based on McDaniel & Associates Consultants Ltd. ( McDaniel & Associates ) reserves report as of December 31, This presentation contains disclosure of forward looking information, certain oil and gas metrics and non-ifrs measures. Please refer to the advisories at the end of the presentation for important information regarding these disclosures. All monetary references are to Canadian dollars unless otherwise indicated.

3 Investing in Canbriam Energy Canbriam s integrated approach supports low cost Montney development & full cycle value creation Prolific BC Montney asset Large, low risk, high return drilling inventory Integrated development strategy Focus on low cost structure and full cycle profitability Experienced management with strong sponsorship 3

4 Canbriam s Altares is located in the northern extension of the Montney The prolific BC Montney has significant well density and peer activity Montney trend Fort St. John Edmonton Vancouver Calgary Canbriam - Altares 30 km 4

5 Cal Daily Gas Rate in 24th month of production (mcf/d) Cal Daily Gas Rate in 12th month of production (mcf/d) Canbriam wells amongst highest deliverability in Northern BC Montney extension 12 & 24 month rates vs. cumulative production highlight over-pressured nature of resource 8,000 7,000 6,000 5,000 4,000 3,000 2,000 1,000 6, month rate vs. cumulative production (Aug ) Canbriam type curve (Upper) Canbriam type curve (Lower) Average Northern Montney wells Canbriam wells (MFB) ,000 1,500 2,000 2,500 3,000 3,500 4, month cumulative production (mmcf) 24 month rate vs. cumulative production (Aug ) Northern BC Montney extension 1,046 total wells with at least 12 months of production; 765 with 24 months of production Wells sorted based on rate in 12 th & 24 th month of production rate as a direct correlation to EUR Canbriam Altares development wells highlight benefits of over-pressured nature of reservoir & use of downhole chokes Northern BC Montney extension 5,000 4,000 3,000 2,000 Canbriam type curve (Upper) Canbriam type curve (Lower) 1,000 Average Northern Montney wells Canbriam wells (MFB) ,000 1,500 2,000 2,500 3,000 3,500 4, month cumulative production (mmcf) Source: GeoScout 5

6 BOE/D Improving decline rates through downhole choke management Sustaining capital requirement is ~$90 million annually to maintain 40,000 boe/d of production capacity Production by well vintage 35,000 30,000 25,000 27% corporate decline rate (1) H H Exploratory Q217: Road bans & b-24-h outage (2) 20,000 15,000 10,000 5,000 0 (1) Calculated by McDaniel & Associates as Proved + Proved Developed Producing (P50 best estimate) forecast decline of 26.5% for 2016 reserves report. (2) On May 18, 2017 the 50 MMcf/d b-24-h facility experienced an isolated fire and is expected to be offline until December 31, Until that facility is brought back online, effective production capacity will be limited to 160 MMcf/d or 30,000 boe/d including liquids. 6

7 Mboe/d Stable production history with strong liquids content Canbriam s production growth reflects addition of phases 1 & 2 of the Altares Processing Facility in 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) Q217: Road bans & b-24-h outage (1) Feb 2015: Phase 1 of Altares Processing Facility (80 MMcf/d ) May 2012: Commissioned 50 MMcf/d b-24-h facility Natural gas Liquids (1) On May 18, 2017 the 50 MMcf/d b-24-h facility experienced an isolated fire and is expected to be offline until December 31, Until that facility is brought back online, effective production capacity will be limited to 160 MMcf/d or 30,000 boe/d, including liquids. 7

8 Efficiency gains tied to improved drilling & completion performance Cost efficiency tied to sliding sleeve technology, less intense completions & improved drill times $12,000 $10,000 $8,000 $6,000 $11,009 Drilling, completion & equipment / tie-in costs by well actual vs. type curve ($M) Type curve $10.6 MM $9,513 $11,325 $9,395 Type curve $8.7 MM $7,212 Drilling & completion costs down ~35% since 2014 $7,000 Type curve $7.0 MM Current type curve drilling, completion & equipment/tie-in: $7.0 million 100% owned water infrastructure has reduced completion costs by $1.0 million per well since 2014 Drilling time improvement & transition to pinpoint sliding sleeve completion design has supported structural cost improvement $4,000 $2,000 $ Current Completion Drilling 8 (1) Drilling improvement relates to improved drill time & technology. Pinpoint fracturing includes cost savings tied to completion intensity reduction & technology improvement. Type curve economics based on $7.0 million drill, complete, equipment & tie-in cost.

9 MMcf/d Infrastructure strategy supports large scale development Canbriam owns & operates all processing infrastructure 100% owned & operated infrastructure: North Altares infrastructure & pad locations Altares Processing Facility consists of: b-72-a gas processing and c-62-a water treatment & recycling hub Natural gas processing facilities: b-24-h: 50 MMcf/d shallow cut refrigeration facility b-72-a: 160 MMcf/d online; scalable to 400 MMcf/d nameplate South Altares: 10 MMcf/d dehy & compression facility online North Fault Block Natural gas processing capacity & planned expansions Potential future expansion of b-72-a to 400 MMcf/d East Fault Block b-72-a phase 2: 80 MMcf/d online Sept 2015 b-72-a phase 3: 120 MMcf/d planned Main Fault Block 100 b-72-a phase 1: 80 MMcf/d online Feb b-24-h: 50 MMcf/d online

10 Altares Processing Facility: scalable to 400 MMcf/d Canbriam owns & operates all 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

11 Competitively advantaged in water sourcing, handling & disposal Integrated water strategy eliminates need to truck water Sourcing & distribution >80% water recycle rate (1) $0.27/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 Disposal well commissioned in Q Passive seismic monitoring in place Provides water takeaway flexibility during periods of lower activity (1) Recycle rates generally increase with activity levels as disposal requirements decrease. (2) 2016 actual operating expenses related to water. Comparative water related operating expenses in 2014 and 2015 were $1.25/boe and $0.74/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. 11

12 Marketing & transportation plan supports long term development Sufficient takeaway capacity to support near term requirements Enbridge T North: 228 MMcf/d firm capacity Actively mitigating unused firm capacity Variable term, scalable with production growth Enbridge T North Pembina Birch Block valve site Future transportation options Enbridge T North firm capacity Mile post 73 NGL terminal TCPL North Montney: 107 MMcf/d firm (Apr 2019E) Canbriam liquids pipeline (construction complete - in service Q4 2017E) MMcf/d TCPL North Montney (expected) ENB T North Canbriam s firm transportation capacity North Montney 107 MMcf/d expected Canbriam water pipeline Canbriam roads Fort St. John Taylor condensate terminal T North: 228 MMcf/d Variable term & scalable Williston Lake TCPL North Montney (proposed) Station 2 Enbridge 0 Jan-14 Jan-15 Jan-16 Jan-17 Jan-18 Jan-19 12

13 Northern B.C. Natural gas pipeline and takeaway capacity Growing egress solutions expected to support B.C. Montney development Jedney Pipeline Current capacity (Bcf/d) Potential expansion (Bcf/d) Expected timing (1) Beg Nig Birley Enbridge T North ~ E Enbridge T South ~1.8 (~2.0 winter) +0.2 Q4 2020E Town Birch TransCanada NGTL (Upper James River) ~ Ongoing debottleneck through 2021E Gundy Blueberry TransCanada Groundbirch ~ E Kobes Inga TransCanada North Montney Q2 2019E Graham Altares Attachie Oak TransCanada Foothills ~ E TransCanada GTN ~ ENB/VSN Alliance ~ E Septimus (1) Based on public disclosures Groundbirch Dawson Groundbirch to Alberta 1.3 bcf/d Swan 13

14 Four key elements to Canbriam s financial strategy Disciplined approach to financial management Priority in 2017 to prudently manage spending with a continued focus on infrastructure spending Flexibility to increase D&C activity to fill existing 40,000 boe/d of nameplate capacity Ensuring capital spending flexibility Maintaining ample liquidity 2017 capital spending funded through cash flow and bank lines Issued a total of US$350 million of HY notes in 2014/2015 to fund development October 2017 bank lines reaffirmed at $350 million On June 30, 2017 $100 million raised through equity issuance on a pro-rata basis with existing shareholders Continue to conservatively manage leverage in the context of private company Key focus on prefunding of capital spending plans in excess of cash flow Managing balance sheet Hedging commodity price risk 2,550 bbls/d of 2017 liquids is hedged with average WTI C$70.69 per barrel 110,000 Gj of 2017 natural gas production is hedged at average $2.62 per gigajoule at Station 2 Physical basis hedges in place to diversify exposure 14

15 Historical financial summary Financial performance reflect improving cost structure and production growth Average production (Mboe/d) Q2 road bans & b-24-h outage 29.9 Adjusted EBITDA (1) (C$ millions) $ $66.0 $83.0 $ $ Q Q Q Capital expenditures (C$ millions) $116 $113 $314 $365 $147 $250 - $ Budget Note: H capital expenditures were $136.5 million. Total cash costs ($/boe) $12.95 $1.97 $3.38 $ Production (boe/d) 9,628 $8.04 $2.22 $0.75 $2.21 $2.29 $2.24 $1.11 $0.64 $1.46 $1.65 $3.41 $2.86 $2.33 $ ,898 $ ,642 $7.59 Q ,363 $9.78 $3.02 $0.87 $2.32 $3.57 Q ,936 Operating G&A Royalties Transportation $6.43 $2.30 $0.37 $1.49 $2.27 Q ,862 (1) Includes risk management gains / losses. 15

16 Composition of revenue stream between natural gas & NGLs Disciplined risk management & active hedging program have supported realized prices $30.00 Revenue by product: Q Q ($/boe) $20.00 $10.00 $22.28 $15.79 $1.12 $3.94 $10.86 $18.34 $11.74 $1.50 $3.45 $6.78 $21.21 $20.15 $12.58 $12.13 $1.15 $1.41 $3.07 $3.84 $8.16 $6.98 $21.62 $16.22 $1.48 $3.83 $11.08 $23.38 $22.51 $22.24 $20.21 $2.50 $1.98 $4.69 $3.99 $14.42 $15.39 $21.97 $18.80 $2.01 $3.78 $13.05 $20.30 $12.84 $2.18 $3.93 $6.85 Realizations: $0.00 NGL Condensate Natural Gas $14.99 $20.05 $15.35 $18.64 $19.37 $28.62 $32.56 $30.12 $28.22 $52.52 $46.06 $40.87 $50.73 $50.16 $57.64 $61.14 $56.65 $50.81 $2.13 $1.33 $1.60 $1.37 $2.18 $2.79 $3.03 $2.51 $1.35 Q Q Q Q Q Q Q Q Q Natural gas Condensate NGL Hedged realization Unhedged realization Production Production (%) Revenue (%) Q Pricing (% Edm Par) Production Production (%) Revenue (%) Pricing (% Edm Par) Production Production (%) Revenue (%) Pricing (% Edm Par) Natural gas (MMcf/d) % 54% % 67% % 64% - Condensate (bbl/d) 2,118 7% 28% 90% 1,866 7% 23% 93% 1,341 7% 26% 93% Natural gas liquids (1) (bbl/d) 2,498 8% 18% 50% 1,682 8% 10% 39% 1,543 9% 10% 31% Total (boe/d) 29, % 100% - 26, % 100% - 17, % 100% - (1) Natural gas liquids include Pentanes plus production. 16

17 Managing Station 2 pricing Active hedging, physical sales basis contracts & high heat content have optimized natural gas pricing $3.50 $3.00 $2.50 High heat content natural gas (1) 13% premium due to heat content M Gj/d Natural gas hedges (at Nov 1, 2017) $2.62 $2.37 $2.00 $ Station 2 weighted average price (C$/Gj) $1.00 Liquids hedges (at Nov 1, 2017) $0.50 Station 2 ($/mcf) Realized price ($/mcf) $0.00 Q2 Q3 Q4 Q1 Q2 Q3 Q4 Q1 Q2 Q Note: Station 2 pricing converted to mcf using standard conversion of GJ/MMBtu 3,500 3,000 2,500 2,000 1,500 1, $70.69 $ ,000 2,550 $ $80 $70 $60 $50 $40 $30 $20 $10 (1) High heat content due to ethane / propane in natural gas stream Volume hedged (bbls/d) WTI weighted average price (C$/bbl) $0 17

18 Managing Station 2 pricing Disciplined approach to risk management has helped optimize natural gas pricing Regional price exposure 2017E Station 2 - hedged 110,000 $2.62 Chicago AECO Sumas Physical contracts (1) 30% Diversified natural gas hubs Physical delivery sales contracts (Gj/d) Hub 2017 expiry 2018 expiry Chicago 10,551 - AECO 10,000-30,550 - Sumas - 15,275 Total 51,101 15,275 Financial hedges 70% Natural gas protected at $2.62/GJ (1) Canbriam has entered physical basis contracts for 2017E & 2018E production, which reflect the contract year November 1 October 31. Custody transfer of the physical basis contracts takes place in British Columbia. Price points less basis as follow: Chicago: Midwest Chicago Citygate; Sumas: NWPL Canadian border IFERC; AECO: AB-NIT Month Ahead (7a) 18

19 $/boe Low cost structure supports full cycle profitability Canbriam s low cost structure drives strong play economics despite low commodity prices $40 $35 $36.51 $35.88 Canbriam cost structure and profitability (2014 Q3 2017) $30 Q2 road bans & b-24-h outage $25 $20 $15 $10 $1.95 $9.48 $23.38 $21.48 $21.39 $22.24 $6.81 $15.51 $4.93 $15.36 $5.26 $9.03 $8.28 $7.48 $21.97 $8.37 $18.80 $7.60 $20.30 $4.72 $4.72 $12.84 $7.48 $7.48 Blended price realization (15% liquids) C$2.50 Station 2; US$50 WTI C$2.00 Station 2; US$50 WTI C$1.50 Station 2; US$50 WTI Capital costs $5 $12.91 $8.04 $6.75 $7.59 $9.46 $6.43 $6.43 Cash operating costs $0 Production (boe/d) , , ,642 Q ,363 Q ,936 Cash costs (operating, royalties, transportation, G&A) Finance costs Realized price (inc. hedging) Q ,862 Q Full cycle DD&A Realized price (before 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. 19

20 Station 2 daily average natural gas price ($/GJ) Canbriam has demonstrated full cycle value Canbriam s low cost structure & prudent risk management have supported full cycle returns Low cost business model supports value creation Operational flexibility required to generate positive returns through any business cycle 8% Return on capital employed (1) Canbriam ROCE $6.00 Prudent risk management protects capital program Station 2 ($/GJ) $5.00 Integrated model provides foundation for full cycle returns 6% 5.3% $ % $4.00 4% $ % $2.00 2% $1.70 $1.65 $1.00 0% $- (1) ROCE 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. See non-ifrs measures at the end of the presentation. 20

21 Investing in Canbriam Energy A fully integrated, natural gas growth company with differentiated resource quality Prolific Montney resource Prolific EUR/well with ~1,100 of Montney vertical thickness on ~62,000 (50% liquids rich) net acres MMboe of gross 1P Reserves (pre-tax PV10 of $1,714 million) (1) MMboe of gross 2P Reserves (pre-tax PV10 of $2,637 million) (1) 100% working interest and operatorship in core lands Large, low risk, high return drilling inventory ~675 net locations in the Altares development area representing ~20 years of drilling inventory at a 3-rig pace Over pressured reservoir (up to 2x) and use of down-hole chokes limits declines and facilitates rapid growth High EURs in the primary Altares development area, with liquid yields between bbls/mmcf Expected IRRs in the main fault block range from ~78% (Upper Montney) to ~47% (Lower Montney) (2) Integrated development strategy Processing facilities are 100% owned & operated; scalable infrastructure supports efficient development 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 strong 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, GE and BlackRock (1) Based on McDaniel & Associates reserves report as of December 31, (2) Pricing assumptions: US$3.00/MMbtu NYMEX; US$50.00/bbl WTI; 0.75 US$/C$ exchange rate. See type curve economics (slide 31). 21

22 SUPPLEMENTAL INFORMATION 22

23 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 23

24 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 2008 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 Rob Froese Chief Financial Officer Responsible for leading capital raising efforts required to fund development through debt, equity and bank credit Formerly VP Finance and CFO of NuVista Energy Ltd. From 2006 to 2014 Over 25 years of financial leadership in the energy industry, including 8 years at Suncor with his final role as Treasurer Gary Gardiner Chief Operating Officer Founding member of Canbriam, formerly CEO of Mahalo Energy/Peregrine Energy Over 29 years of industry experience including leadership roles at Encana Corporation as Vice President Fort Nelson Business Unit & Vice President USA Northern Rockies Business Unit Various operational leadership roles with Alberta Energy Company, City of Medicine Hat and Home Oil John Nieto Chief Technology Officer Co-founder of Canbriam, provides oversight and vision for all aspects of technical integration and reservoir characterization for the company Over 35 years of industry experience, including 14 year career with ExxonMobil and Mobil, culminating with being named global coordinator of formation evaluation Donna Phillips Executive Vice President, Corporate Development Responsible for Stakeholder Relations, Land, and Business Development 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 24

25 True Vertical Depth (m) Differentiated resource quality in the BC Montney Four key attributes that differentiate the Altares Montney 1. Over pressured reservoir Up to 2 times over pressured within Main Fault Block Downhole choke strategy enhances EUR, improves well economics, sustains liquids yield and supports low declines Reservoir Pressure (kpa) 0 10,000 20,000 30,000 40,000 50,000 60, Over pressured (15-20 kpa/m) Normally pressured (10 kpa/m) Canbriam development wells (Main Fault Block) Canbriam development wells (North Fault Block) 1,000 1,500 2,000 2, kpa/m 15 kpa/m 20 kpa/m 3,000 kpa psi 20,000 2,900 Overpressure Source: ITG, raw data from Geoscout Note: psi/foot = 10 KPa/meter Normal pressure 3,500 4,000 40,000 5,800 60,000 8,700 Canbriam Montney pressure gradient mapping Canbriam well pressure vs. target depth 25

26 Differentiated resource quality in the BC Montney Four key attributes that differentiate the Altares Montney 2. Subsurface compartmentalization Leads to distinct high pressure regions with consistent well results Main Fault Block represents majority of near term development plan Highest over-pressure region (up to 2x) Consistent well results ~20 years inventory at a 3-rig pace North & East Fault Blocks demonstrate high liquids yields South Fault Block is located in the dry gas window Main Fault Block North Fault Block South Fault Bock East Fault Block 26

27 Lower Upper Differentiated resource quality in the BC Montney Four key attributes that differentiate the Altares Montney 3. Significant thickness Five commercial intervals Average thickness is ~1,100 feet 4. Strong liquids component 2016 liquids yield: ~27 barrels per MMcf ~60% condensate; ~20% propane; ~20% butane 7 Tested zones Liquids rich gas Commercial Intervals1 & 2 C5 C4 Oil window Commercial Interval 3 C2 T1 Enbridge T North Commercial Interval 4 T2 Commercial Interval 5 T3 Dry gas window Source: Canbriam Canbriam Montney - liquids mapping 27

28 F&D ($/boe) Recycle ratio Significant reserves growth with high liquids content Canbriam s 2P bookings reflect consistent well performance 2P Reserve growth (MMboe) $25 $20 $ P F&D costs & recycle ratio (1) Gas Liquids $10 $5 $0 $21.00 $12.00 $11.50 $12.00 $7.68 $8.00 $5.31 $ year avg: F&D Recycle ratio Summary of gross reserves as of Dec 31, 2016 (2) Category Natural Gas (Bcf) NGLs (MMbbls) Total (MMboe) Total (%) PV 10% ($MM) (3) Net Locations Proved Developed % $ Proved Undeveloped % $1, Total Proved 1, % $1, Probable (4) % $ Total Proved + Probable 1, % $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 calculated on a gross company interest basis, before royalties and based on a 3 rig case through the current 7 year development plan. Categories may not total due to rounding. (3) Before tax and based on McDaniel & Associates pricing as of 1/1/17. Future development capital (FDC) reduced by 16% to $1.7 Billion. (4) Probable reserves shown are for the 53 Probable Locations plus the Probable component of all the other 2P wells.

29 Illustrative type curve economics Main Fault Block Type well statistics represent the current planning basis for Canbriam Single well statistics Well properties Upper Montney Main Fault Block 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% 8% Initial liquids yield (bbls/mmcf) Well economics (3) IRR 78% 47% NPV ($MM) $11.0 $6.4 Drilling, completion & tie-in/equipment costs ($MM) $7.0 $7.0 Operating & transportation costs (4) ($/boe) $6.75 $5.69 Average royalty rate (5) 17% 12% (1) Type curve and liquid yields (free condensate & plant liquids) represents current planning basis for Canbriam. (2) Assumes shrinkage of 9%. (3) Well economics are calculated on a before-tax basis using flat pricing assumptions: US$3.00/MMbtu Nymex; US$60.00/bbl WTI; C$3.00/GJ AECO; C$2.65/GJ Station 2; 0.75 US$/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. (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 $2.4 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. 29

30 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 30

31 PnP 2013 PnP 2014 PnP 2015 PnP 2015 NCS 2016 PnP 2016 NCS Average Sand Pumped per m lateral length (T/m) Average water pumped per m lateral length (M 3 /m) PnP PnP PnP PnP PnP NCS PnP NCS Well Count by completion type Optimizing completion design Migration to pinpoint cemented sliding sleeve technology has resulted in more efficient placement of sand Well count by completion type Migration towards sliding sleeve technology driven by: More efficient placement of sand within fracture due to pinpoint nature of technology Natural fracture network within reservoir requires less proppant Average proppant and water pumped per meter Sand (LHS) Water (RHS) Canbriam maximized completion intensity through 2016 Driven by desire to understand effective limits of proppant loading & well spacing Proppant and water loading rates peaked in early

32 Proven capability drilling in anomalously 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 (18 22 kpa/m gradient) Improved well design & longer reach laterals improves drilling efficiency and mitigates HSE risk Depth (mmd) 0 Canbriam drilling days vs competitor (>1,800 kg/m 3 mud) $2.50 Canbriam drilling efficiency ($M/meter drilled) 500 1,000 1,500 Nik Canbriam (2015) Canbriam (2016) Peer (Altares Montney) Peer (Graham Montney) $2.00 Drill cost per meter of total measured depth 2,000 2,500 Nordegg Doig Montney $1.50 3,000 $1.00 3,500 4,000 4,500 $0.50 5,000 5, Days (spud to rig release) Source: Frac Database $

33 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 33

34 Optimized development spacing in 2016 Three Upper Montney & two Lower Montney layers at 300 meter spacing Previous development plan included 4 layers at 200 meters spacing Future Development Capital reduced by ~16% in 2016 Liquids rich inventory represents over 20 years of development at 3 rig pace North Altares Liquids rich South Altares Dry gas Well placement interval Working interest Initial liquids yield (1) Net acres Thickness (feet) Well spacing (meters) Additional well locations (2) Additional well locations (3) C5 100% 42 36, Upper Montney Lower Montney C4 100% 42 36, C2 100% 42 36, T2 100% 24 36, T3 100% 24 36, Total 5 zones 100% 180,000 1, (1) Includes average free condensate and plant liquids for first month of production. Liquids yield is representative of North Altares Main Fault Block type curve. (2) Includes 69 PDP wells and PUD, Probable and de-risked development locations for Main/North/East Fault Blocks. (3) Represents locations that have not been de risked and which requires higher natural gas price (NYMEX $ $5.00/MMbtu) to be economic with today s technology. Average working interest in South Altares is 73%. Canbriam has no near term plans to drill in South Altares.

35 Evolution of completion optimization Completion efficiency improving through technology advancement & integrated technical approach Initial development ( ) 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 Development phase ( ) 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 Current design (2016 Q2 2017) Pinpoint sliding sleeve tonne/meter proppant loading meter cluster spacing stages per well Average horizontal length ~2,040 meters Main Fault Block; Testing North & East Fault Blocks 5 zones (3 Upper, 2 Lower) 300 meter well spacing Parent/child well management H1 2017: 12 wells 35

36 Daily Gas Rate (mcf/d) Daily Gas Rate (mcf/d) Development plan focused in the prolific Main Fault Block Canbriam s Main Fault Block is substantially de-risked and represents the majority of the next 5 years development Daily Raw Gas Production by Well Upper Montney Development Wells Daily Raw Gas Production by Well Lower Montney Development Wells 10,000 10,000 9,000 8,000 Upper Montney MFB Actuals 9 Bcf type curve (UM) 9,000 8,000 Lower Montney MFB Actuals 8 Bcf type curve (LM) 7,000 7,000 6,000 6,000 5,000 5,000 4,000 4,000 3,000 2,000 1,000 3, wells 14 wells 2,000 1, Cumulative Raw Gas (bcf) Cumulative Raw Gas (bcf) Production Q Q Q Q Q Natural gas (mcf/d) 151,473 98, , , ,572 Upper Development wells (at Sept 30, 2017) Lower Condensate production (bbl/d) 2,118 1,221 1,817 1,746 1,635 Natural gas liquids (bbl/d) 2,498 1,308 2,531 2,141 2,222 Total (boe/d) 29,862 18,936 28,363 28,075 25,286 Main Fault Block North Fault Block 6 1 East Fault Block 2 1 Total wells

37 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 Natural gas production 40,000 Boe/d nameplate capacity 30,000 Boe/d capacity (1) ,000 Boe/d nameplate capacity May-16: MP73 outage Q217: Road bans & b-24-h outage (1) Sept-15: Plant turnaround 0 6,000 5,000 4,000 Liquids production , ,000 1,000 Sept-15: Plant turnaround May-16: MP73 outage Q217: Road bans & b-24-h outage (1) 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 and is expected to be offline until December 31, Until that facility is brought back online, effective production capacity will be limited to 160 MMcf/d or 30,000 boe/d including liquids. 37

38 Historical netbacks Canbriam s low cash costs drive solid margins 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 (7.46) (3.17) (1.14) (2.30) (5.40) (8.02) (8.63) (6.60) (6.49) (5.02) (5.46) (9.59) (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. 38

39 Supplemental reserves information 2016 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 (274) (10) (57) (178) (9) (39) Technical revisions (14) 2 (3) (136) (6) (30) (150) (8) (33) Category change 110 (1) 21 (139) - (27) (29) (1) (6) Extensions & Improved Recovery Discoveries Acquisitions Dispositions Economic Factors Production (50) (1) (9) (50) (1) (9) December 31, , , Summary of Future Development Costs (2) Proved (MM) Probable (MM) Proved + Probable (MM) December 31, 2015 $1,278 $761 $2,039 Changes ($3) ($317) ($320) December 31, 2016 $1,275 $444 $1,719 (1) Reserves are calculated on a gross company interest basis, before royalties and based on a 3 rig case through the current 7 year development plan. Categories may not total due to rounding. (2) Undiscounted, as calculated by McDaniel & Associates as of 12/31/16 based on a 3 rig case through the current 7 year development plan 39

40 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 2017E cost structure, drilling activities and liquids yield; inventory of drilling locations; anticipated recommissioning date of the 50 MMcf/d b-24-h facility; and anticipated service date for liquids pipeline. 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. 40

41 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, 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. 41

42 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. 42

43 Canbriam Energy Inc. 2100, nd Street SW Calgary, AB Canada T2P 1M4 Tel: Paul Myers President & Chief Executive Officer pmyers@canbriam.com Rob Froese Chief Financial Officer rfroese@canbriam.com Bill Stait Director, Investor Relations and Corporate M&A bstait@canbriam.com Copyright 2015 Canbriam Energy Inc. All rights reserved.