Corporate Presentation January 2017 North Montney: Scale, Growth - PowerPoint PPT Presentation

Corporate Presentation January 2017

North Montney: Scale, Growth and Value NEBC Liquids-Rich • Well results indicate 7-11 Bcf EUR at low cost High Montney • Liquids yield of 35-50 bbl/MMcf 218,000 net acres Quality • Half-cycle IRR of 75% at $2.50/GJ AECO 1 Asset • 341 sections of Montney rights 2 Material • Contiguous, 100% WI with liquids-rich potential Position • Over 78 Tcf of estimated gas-in-place High • Capable of achieving 100,000 boe/d in five years Growth • 52 Hz wells drilled at year-end 2016 • Inventory of over 2,800 Hz locations Potential 10 km • $850 MM equity raised to date 3 Well • Investors: Azimuth Capital Management, Canada FT ST JOHN Pension Plan Investment Board & Warburg Pincus Financed MONTNEY • $200 MM bank line 4 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 Dec 31, 2016 4. $123 MM undrawn at Dec 31, 2016 2

Building Momentum: Development Drilling & Infrastructure Production Growth 25,000 Corporate production Avg. Daily Production (boe/d) Expansion of owned infrastructure • Dec 2016: 16,500 boe/d (16% liquids) 20,000 • Dec 2017 budget: 24,000 – 26,000 boe/d (17% liquids) 15,000 Delineation Development 10,000 Capital program • Focused on multi-well development pads 5,000 • 2016: $89 MM (incl. $50 MM infrastructure) - • 8 Hz wells drilled, 8 completed, 16 tied in Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 • 2017 budget: $180 MM (incl. $92 MM infrastructure) 2013 2014 2015 2016 2017E • 19 Hz wells drilled, 16 completed, 16 tied in • North Aitken Creek expansion to 110 MMcf/d Reserves Growth 400 • Long-lead items for second gas plant 350 300 Reserves (MMboe) 2015 YE reserves - independent evaluation 1 250 • 1P = 127 MMboe (NPV10 $725 MM) 200 • 2P = 383 MMboe (NPV10 $1,727 MM) 150 • F&D (incl. FDC) 2,3 : 1P $6.84/boe; 2P $2.55/boe 100 • FD&A (incl. FDC) 3 : 1P $8.37/boe; 2P $3.70/boe 50 - 2012 2013 2014 2015 1. Evaluated by GLJ, Montney only - excludes Duvernay which was divested April 2016 2. Excludes Carmel Bay acquisition PDP PDNP + PUD Probable 3. Capital costs include the cost of the North Aitken Creek Gas Plant & land 3

Robust Economics: Low Cost, Liquids-Rich, Hot Gas Black Swan Montney Half-Cycle Economics 1 Assumptions 160% 7.5 Bcf (8.6 Bcfe) D&C Cost ($MM, excl. $0.4 MM tie-in) $4.6 9.0 Bcf (10.4 Bcfe) 140% EUR (Bcf) 9.0 10.5 Bcf (12.0 Bcfe) IP30 - Gas (MMcf/d, raw) 7.0 120% IP30 - Total (boe/d) 1,300 100% Heat Content (MMBtu/mcf) 1,150 Liquids Yield (bbl/MMcf) 40 IRR 80% Royalty Drilling Credit ($ MM) $1.05 60% Opex & Transport ($/boe) $4.30 40% 9 Bcf Well Economic Outcome: $2.50/GJ & US$50/bbl B-tax NPV ($MM) $7.1 20% B-tax IRR 75% 0% PI Ratio (NPV10) 1.4x $2.00/GJ AECO $2.50/GJ AECO $3.00/GJ AECO Netback ($/boe) 2 $14.90 $40/bbl WTI $50/bbl WTI $60/bbl WTI F&D ($/boe) $2.90 Unrestricted vs. Restricted Type Curve Recycle Ratio 4.3x 10,000 2,500 Breakeven (fixed WTI) $0.85/GJ Cumulative Production (MMcf) Daily Production (mcf/d) Payout (months) 15 8,000 2,000 9.0 Bcf Wells Breakeven: 6,000 1,500 Choking initial production has no US$50/bbl WTI: ~$0.85/GJ AECO material impact to cumulative production at 365 days 4,000 1,000 US$60/bbl WTI: ~$0.60/GJ AECO 2,000 500 Revenue Enhanced by Liquids - - Half-cycle Revenue Mix at 40 bbl/MMcf 3 1 30 59 88 117 146 175 204 233 262 291 320 349 378 407 436 465 494 523 552 581 610 639 668 697 8% Days on Production Gas Unrestricted 9 Bcf Restricted 9 Bcf 29% C5+ Unrestricted Cum Restricted Cum 62% C3/C4 1. Inputs provided in the Appendix 2. Netback over the first year, assumes Station 2 delivery 3. At $2.50/GJ AECO, US$50/bbl WTI, C$1.25/US$ FX and -$0.30/GJ Station 2 diff 4

Continuous Improvement in Well Deliverability Average EUR/Well 1 Results demonstrate operational success 10.0 • Average EUR >9.0 Bcf on most recent 24 Hz wells 9.0 8.0 • Increased number of stages 7.0 EUR (Bcf) • Well placement optimized 6.0 5.0 • Continuous review of emerging technologies & 4.0 optimization of wellbore design to lower costs and 3.0 enhance recoveries 2.0 1.0 - Continuous program drives lower costs 2012 (4 wells) 2013 (6 wells) 2014 (8 wells) 2015 (15 wells) 2016 (7 wells) • Improved operational efficiencies associated with Piloting Development a continuous program and pad drilling • Cost reductions from installed water infrastructure • Completions timed to minimize costs and fill Decreasing Costs on Multi-well Pads $7.0 infrastructure $6.4 MM • Longest well to date rig released in December $6.0 D&C Costs ($MM/well) $5.0 $4.6 MM $4.5 MM Drilling adds: 17,500 boe/d/rig annually $4.1 MM $4.0 • Continuous one-rig program • 20 Hz wells/rig/year $3.0 • F&D cost <$3/boe 2 $2.0 • Capital efficiency <$6,000/boe/d 2 $1.0 $0.0 2014 2015 2016 2017 Drilling Cost Completion Cost 1. EUR/Well excludes Carmel Bay acquired wells 2. Based on IP 365 of 875 boe/d (half-cycle 9.0 Bcf EUR type curve) 5

Type Curve Supported by Multi-Well Development Pads Upper Montney Multi-Well Pad Performance: Average Rate Per Well • Southern portion of asset base 10,000 delineated by multi-well pads Type Curves 9,000 7-H Pad Average • Established inventory of >450 top-tier 19-E Pad Average 8,000 54-D Pad Average locations 7,000 22-C Pad Average 92-C Pad Average • Minimal maintenance capital: 6,000 Mcf/d 5,000 • $35 MM holds production flat at 4,000 15,000 boe/d annually 10.5 Bcf 3,000 9.0 Bcf 7.5 Bcf 2,000 1,000 0 0 30 60 90 120 150 180 210 240 270 300 330 360 Normalized Days c-7-H 5 well pad b-19-E Pad Wells Avg D&C Avg EUR completed Q4/2014 3 well pad ($MM) (Bcf) completed 2015 & 2016 92-C 6 well pad c-7-H 5 6.4 7.2 1 completed Q3/16 a-54-D 8 well pad a-54-D 8 4.6 8.4 completed Q3/15 b-22-C 7 4.1 10.3 1 a-92-C 6 3.9 9.7 b-22-C 7 well pad b-19-E 3 3.7 2 9.7 completed Q4/15 1. Pads incl. one Lower Montney pilot well not incl. in avg EUR 2. Avg cost for two 2016 wells, 2015well cost $9 MM D&C 10 km 6

Infrastructure Investment Strategy 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 • Long lead equipment included in 2017 budget 10” 6” • Expect Phase 1 on-stream Q4 2018 Infrastructure investment 8” 50 MMcf/d compression & • At 2016 YE: $220 MM dehy, volumes flow to 10” • 2017 Budget: $90 MM McMahon for Gathering trunk- processing lines built H1/16 10” sales gas line; connects to Spectra T-North system 10 km Pipeline infrastructure in place to support >110 MMcf/d • 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 Future Growth: Owned & Operated Gas Plant North Aitken Creek Gas Plant Production Phase 1 capacity: 10,000 boe/d 60 120 • Plant optimized for above average C5+ yield from 50 100 22-C pad and to maximize netbacks: Gas Production (MMcf/d) Liquids Yield (bbl/MMcf) • Condensate/C5+ yield: 30 bbl/MMcf 40 80 • C3/C4 yield: 10 bbl/MMcf 30 60 • Gas heat content: 1,165 MMbtu/mcf • Capable of increasing C3/C4 yield to 20 bbl/MMcf 20 40 10 20 Cost structure reflects ownership advantage 0 0 Jan-16 Feb-16 Mar-16 Apr-16 May-16 Jun-16 Jul-16 Aug-16 Sep-16 Oct-16 Nov-16 • Operating costs <$3.00/boe Inlet Gas (MMcf/d) Inlet Capacity (MMcf/d) • Plant volumes deliver field netbacks >$13/boe in Q3 C5+ Yield (bbl/MMcf) C3/C4 Yield (bbl/MMcf) • Strong netbacks enhanced by liquids production • Produced water recycled for ongoing operations North Aitken Gas Plant Q3 2016 Operating Netback $20.00 Royalties $16.00 Transportation Field netback Operating Costs $12.00 $/boe $13.40/boe LPG Condensate $8.00 Gas $4.00 $0.00 Costs Revenues 8