Corporate Presentation May 2017
North Montney: Scale, Growth, Value • Half-cycle IRR of 75% at $2.50/GJ AECO 1 High Liquids-Rich Montney • Average 9 Bcf EUR over last 30 Hz Upper Montney wells 218,000 net acres Quality • Recent well costs <$4.0 MM/well 100% working interest Asset • Liquids yield of 30-50 bbl/MMcf Material • 341 net sections of Montney rights 2 Scalable • 52 Hz wells drilled at YE ‘16 Position • Inventory of over 2,800 Hz locations Growth • Development plan achieves 100,000 boe/d in five years Supported by • Gas egress commitments growing to >395 MMcf/d Egress • Contracts held on three major pipeline systems 10 km Infrastructure • Owned & operated infrastructure ($275 MM at Q2/17) Advantage • Operating cost <$2.50/boe through operated gas plant Strong • $850 MM equity raised to date 3 (Azimuth Capital FT ST JOHN Balance Management, CPPIB & Warburg Pincus) MONTNEY Sheet • $200 MM bank line 4 ; US$100 MM term debt 5 EDMONTON BRITISH 1. EUR 9.0 Bcf, US$50/bbl WTI, C$1.25/US$ FX, $0.30/GJ Station 2 differential, $5 MM DCET ALBERTA COLUMBIA 2. 312 net DSUs where one DSU = 700 acres 3. $800 MM drawn, $50 MM undrawn at Mar 31, 2017 4. Undrawn post closing of term debt issue 5. US dollar denominated, matures Jan 2024, 9% coupon 2
Building Momentum Through Pad Drilling Production Growth 25,000 Corporate production Avg. Daily Production (boe/d) Expansion of owned • Dec 2016: 16,650 boe/d (16% liquids) infrastructure 20,000 • Q1 2017: 16,732 boe/d (15% liquids) • Dec 2017 budget: 24,000 – 26,000 boe/d (17% liquids) 15,000 Delineation Development 10,000 5,000 2017 Capital program - • $180 MM (incl. $92 MM infrastructure) Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 • 19 Hz wells drilled 2013 2014 2015 2016 2017E • North Aitken Creek plant expansion to 110 MMcf/d Reserves Growth 500 450 400 2016 YE reserves - independent evaluation 1 350 Reserves (MMboe) • 1P = 171 MMboe (NPV10 $898 MM) 300 250 • 2P = 478 MMboe (NPV10 $2,125 MM) 200 • FD&A (incl. FDC) 2 : 150 • PDP: $5.86/boe 100 • 1P: $7.63/boe 50 • 2P: $5.78/boe - 1. Evaluated by GLJ Petroleum Consultants 2012 2013 2014 2015 2016 2. Capital costs include the cost of the North Aitken Creek Gas Plant & land & changes in Future Development Capital (FDC) PDP PDNP + PUD Probable 3
Robust Economics: Low Cost, Liquids-Rich, Hot Gas Assumptions 9.0 Bcf Wells Breakeven: D&C Cost ($MM, excl. $0.4 MM tie-in) $4.6 US$50/bbl WTI: ~$0.85/GJ AECO EUR (Bcf) 9.0 IP30 - Gas (MMcf/d, raw) 2 7.0 IP30 - Total (boe/d) 1,300 Black Swan Montney Half-Cycle Economics 1 Heat Content (MMBtu/mcf) 1,150 Liquids Yield (bbl/MMcf) 36 160% 7.5 Bcf (8.6 Bcfe) Royalty Drilling Credit ($ MM) $1.05 9.0 Bcf (10.4 Bcfe) 140% Opex & Transport ($/boe) $4.30 10.5 Bcf (12.0 Bcfe) 120% 9 Bcf Well Economic Outcome: $2.50/GJ & US$50/bbl B-tax NPV ($MM) $7.1 100% B-tax IRR 75% PI Ratio (NPV10) 1.4x IRR 80% Netback ($/boe) 3 $14.90 F&D ($/boe) $2.95 60% Recycle Ratio 4.3x Breakeven (fixed WTI) $0.85/GJ 40% Payout (months) 15 20% 0% Revenue Enhanced by Liquids $2.00/GJ AECO $2.50/GJ AECO $3.00/GJ AECO Half-cycle Revenue Mix at 36 bbl/MMcf 4 $40/bbl WTI $50/bbl WTI $60/bbl WTI 6% Gas Robust economics at $2.00/GJ AECO 30% C5+ 9 Bcf type curve supported by last 30 Upper Montney Hz wells 64% C3/C4 1. Inputs provided in the Appendix 2. Black Swan chokes wells during initial production for operational reasons, no material impact on cumulative 365 day production 3. Netback over the first year, assumes Station 2 delivery 4. At $2.50/GJ AECO, US$50/bbl WTI, C$1.25/US$ FX and -$0.30/GJ Station 2 diff; liquids yield is 20 bbl C5+ and 16 bbl C3/C4 4
Repeatable Well Deliverability at Low Cost Upper Montney Wells (by completion date) 14.0 Ongoing operational success 12.0 • Avg EUR: 9.0 Bcf since Q3/13 (30 wells) Expected EUR (Bcf/well) • Repeatable and predictable outcomes 10.0 9 Bcf 8.0 6.0 Continuous program drives lower costs 4.0 • Operational efficiencies of a continuous 2.0 program & pad drilling 0.0 b-B79-G a-A11-A a-B20-H b-A22-C a-92-C c-45-D a-C20-H b-17-H c-B7-H c-A7-H c-7-H b-19-E b-54-D b-A54-D a-54-D a-A54-D a-B54-D a-C54-D b-B54-D a-D54-D b-95-E b-C22-C b-D22-C b-E22-C b-F22-C b-G22-C a-A92-C a-B92-C a-C92-C a-D92-C a-E92-C a-A20-E b-B19-E • Cost reductions from installed water infrastructure 2012 2012 2013 2014 2015 2016 • Completions timed to minimize costs and fill processing infrastructure Decreasing Costs on Multi-well Pads $7.0 $6.4 MM Evolving Wellbore Design $6.0 D&C Costs ($MM/well) $4.2 - $4.8 MM 1 • Testing well length, proppant loading, stage $5.0 $4.6 MM $3.8 MM count and inter-well spacing to optimize $4.0 economics: $3.0 • Sand loading increased by 30% $2.0 • Completed length increased by 50% $1.0 • Increased service costs (fracturing) $0.0 2014 2015 2016 2017E 1. Annual budget $4.5 MM, range includes cost of base design $4.2 MM Drilling Cost Completion Cost Design Evolution +$0.6 MM for cost increases on design evolution; base design includes 1,800 m lateral, 30 stages, 60 T/ frac 5
Pad Operations Provide Capital Efficient Growth Upper Montney Multi-Well Pad Performance Tracking Type Curves 10,000 Pad Year Wells/ Avg Avg Type Curves 9,000 Completed Pad D&C EUR 7-H Pad Average 8,000 19-E Pad Average ($MM) (Bcf) 22-C delivering >130% IRR 3 54-D Pad Average 7,000 7.2 1 22-C Pad Average 7-H 2014 5 6.4 6,000 92-C Pad Average Mcf/d 54-D 2015 8 4.6 8.4 5,000 22-C 2015 7 4.1 10.3 1 4,000 3,000 10.5 Bcf 92-C 2016 6 3.9 9.7 9.0 Bcf 2,000 7.5 Bcf 19-E 2015/2016 3 3.7 2 9.7 1,000 0 0 30 60 90 120 150 180 210 240 270 300 330 360 390 420 450 480 Normalized Days 19-E 7-H 3 well pad • 22-C pad paid out in <1 year 5 well pad 92-C • Drilling efficiency 4 6 well pad • Add 17,500 boe/d/rig annually 54-D 8 well pad • F&D cost <$3/boe • Capital efficiency <$6,000/boe/d 22-C 7 well pad 1. Pads incl. one Lower Montney pilot well not incl. in avg. EUR 2. Avg cost for two 2016 wells, 2015 well cost $9 MM D&C 3. At $2.50/GJ AECO and US$50/bbl WTI 10 km 4. Based on IP 365 of 875 boe/d (half-cycle 9.0 Bcf EUR type curve, $5 MM DCET) 6
Infrastructure Advantage 100% owned & operated infrastructure Plant 1: North Aitken Creek Gas Plant • Phase 1: 50 MMcf/d 110 MMcf/d Existing gathering trunk-lines 6” raw capacity • Phase 2: 60 MMcf/d 6” • Liquids recoveries capable of ~40 bbl/MMcf (>50% C5+) North Aitken Creek • Phase 2 on-stream scheduled June 2017 Gas Plant 110 MMcf/d capacity Plant 2: 198 MMcf/d facility 10” • Engineering in progress 10” • Long lead equipment included in 2017 budget 6” • Expect Phase 1 on-stream Q4 2018 8” 50 MMcf/d Infrastructure investment compression & dehy, volumes • At 2016 YE: $220 MM flow to 10” • 2017 Budget: $92 MM McMahon for Gathering trunk- processing lines built H1/16 10” sales gas line; connects to Enbridge T-North system 10 km Pipeline infrastructure in place to support >110 MMcf/d at plant • 35 km of gathering lines • 20 km of raw gas lines (to third party facilities) • 10 km sales gas line (gas plant to T-North) North Aitken Plant Compressors 7
Low Cost Growth: Owned & Operated Gas Plant North Aitken Creek Gas Plant Production 60 100 Phase 1 capacity: 10,000 boe/d 90 • Plant optimized to maximize netbacks: 50 80 Liquids Yield (bbl/MMcf) Gas Production (MMcf/d) • Condensate/C5+ yield: >20 bbl/MMcf 70 40 • C3/C4 yield: 10 bbl/MMcf 60 30 50 • Gas heat content: 1,170 MMbtu/mcf 40 • Recent wells initially at total C5+ yields as high as 20 30 40 bbl/MMcf 20 • Stable total C5+ yield: 20 bbl/MMcf 10 10 • Capable of increasing C3/C4 to 20 bbl/MMcf 0 0 Jan-16 Mar-16 May-16 Jul-16 Sep-16 Nov-16 Jan-17 Mar-17 Inlet Gas (MMcf/d) Inlet Capacity (MMcf/d) C5+ Yield (bbl/MMcf) C3/C4 Yield (bbl/MMcf) North Aitken Gas Plant Q1 2017 Operating Netback Operating netback reflects ownership advantage $25.00 $1.46 • Operating costs <$2.50/boe $20.00 Royalty $6.48 • Plant operating netbacks >$17.50/boe in Q1/17 Transportation Field netback $15.00 $/boe • Produced water recycled for ongoing operations Operating Cost $17.64/boe C3/C4 Revenue $10.00 C5+ Revenue $15.06 Gas Revenue $5.00 $1.26 $1.60 $2.50 $0.00 Costs Revenues 8
North Aitken Plant – Phase 2 Commissioning June 2017 2016: Phase 1 Q1 2016 Additional liquids handling Increased gas through put capacity 2017: Phase 2 Expansion Q2 2017 9
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