Private Energy Conference January 2017 North Montney: Scale, Growth - PowerPoint PPT Presentation

Private Energy Conference 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

Consistent Reservoir Characteristics, Consistent Results Upper Montney Net Pay Map (1% Porosity Cutoff) Net pay and porosity continuous across Aitken development area • The reservoir across the southern development area shows little variation ranging from ~50 – 70m in thickness and A A’ ~4.5 – 6.5% porosity • This consistent reservoir has led to a narrow range of pad 60 results of 8.5 – 10.5 Bcf/well over most of the land • Extensive grid of 2D and 3D seismic confirms the reservoir continuity and shows most of the area is structurally quiet except for an area of small structures in the northwest where pad results have averaged 7 Bcf 10 km Black Swan Hz Beg Black Swan Hz Jedney Black Swan Hz N Aitken Black Swan Hz Nig Black Swan Hz Nig A’ A A-020-H/094-G-01 B-019-E/094-H-04 C-045-D/094-H-04 B-A022-C/094-H-04 A-092-C/094-H-04 Upper Montney Gamma Marker Lower Montney 0 GR (API) 150 24 Porosity (%) -6 6

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 7

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 8

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 9