SEPTEMBER 10, 2019 SEPTEMBER PRESENTATION
CORPORATE OVERVIEW – IT’S BEEN A ROUGH RIDE CORPORATE INFORMATION SHARE PRICE PERFORMANCE Ticker Symbol TSX:DEE Basic Shares Outstanding (mm) 185.5 S&P/TSX Market Capitalization (mm) $22.3 (1) / Credit Facility (mm) $85.7/ $100.0 Bank Debt 5 Year Senior Secured Notes (mm) $105.0 Liquids-Rich Montney Maturity Date: July 2021 Group Down 30 to 75 percent DEE SENIOR CREDIT FACILITY $110 Net Bank Debt ($ mm) (inc/ working capital) $100 $90 $80 4 well Pad Project On Production $70 Q2/19 $60 Q3/18A Q4/18A Q1/19A Q2/19A Q3/19E Q4/19E (1) Bank debt as of March 31, 2019 includes working capital and excludes $7.4 million LC's Debt & WC Bank Line of outstanding Letters of Credit 2 September 2019
BIGSTONE – PROLIFIC, LIQUIDS RICH MONTNEY Pure play MONTNEY E&P company with WORLD CLASS ASSETS : Successful delineation drilling Grande Prairie Bigstone to the west and south Montney Edmonton Successful pad development in West Bigstone Calgary Growing condensate production and high stable yields Integration of owned infrastructure leading to lower operating costs Alliance / Chicago natural gas market access 3 September 2019
WEST BIGSTONE: DELINEATION SHIFTS TO DEVELOPMENT Ultra-rich West Bigstone: 15-10 and 16-10 On Production 4 well pad on production Section 10 4 Well Pad 15-10 and 16-10 On Production offsets are best wells drilled LTD by DEE Section 19 and 31 Sections 19 and 31 wells are also ultra-rich 5 Wells On Production condensate wells Competitor Multi-Well Pad Waiting on Competitor Completion License 4 September 2019
WEST BIGSTONE: SUCCESS IN LOWER LA YER COULD DOUBLE INVENTORY Section 10 DEE 4 Well Pad On Production XTO Competitor DEE 6 wells on Section 10: Multi-Well Pad Targeting Upper D1, D2, D3 Waiting on Competitor 275 m well spacing Completion License 15-20 m vertical separation Competitor 2 wells drilled: Targeting C, D1, Lower D2 Pad built for up to 16 wells 200 m well spacing 5 September 2019
CRACKING THE COMPLETION CODE AT WEST BIGSTONE Montney Frac Generation Design Evolution 200 2,000 Planned stages Sand placed Evolution to more stages and 180 1,800 sand moving to West Bigstone 160 1,600 Planned Stages Sand Placed (lb/hz ft) More at West - less at East 140 1,400 120 1,200 100 1,000 Optimizing frac sizes to 80 800 maximize capital efficiency 60 600 40 400 20 200 Successful result of 65 stage 0 0 hybrid frac at 16-10, 15-10 and Montney Drill & Complete Capital Efficiency 03/16-31 at West Bigstone $20,000 IP30 IP90 $15,000 On-going testing of new ball $/boepd drop technologies and extreme $10,000 limited entry cased hole $5,000 completions $0 2012 2013 2014 2015 2016 2017 2018 6 September 2019
MOST RECENT WEST BIGSTONE RESULTS Initial Production (IP) Rate Well Performance (1) Well (2) Frac Design Horizontal Number IP30 IP90 IP180 IP365 Generation Length of Fracs Total Sales Field Condy Total Sales Field Condy Total Sales Field Condy Total Sales Field Condy to Gas Yield to Gas Yield to Gas Yield to Gas Yield (metres) (boe/d) (bbl/mmcf) (boe/d) (bbl/mmcf) (boe/d) (bbl/mmcf) (boe/d) (bbl/mmcf) 15-19 5th 2,862 49 1,828 228 1,300 183 974 168 646 165 16-07 5th 2,853 28 607 319 565 208 457 183 352 172 16-10 6th 2,855 64 1,441 317 1,234 181 1,035 150 794 124 16-19 5th 2,860 34 953 245 722 188 569 167 418 153 02/16-31 3rd 2,944 49 1,095 340 800 304 613 279 02/15-19 3rd 2,687 50 998 245 754 199 586 180 15-10 6th 2,963 64 1,294 245 1,100 153 781 158 02/15-10 7th 2,869 80 980 233 852 170 03/16-31 6th 2,938 64 1,173 394 902 312 714 272 14-10 7th 2,945 79 1,171 330 945 238 41 (3) 12-10 8th 2,636 756 558 585 408 40 (3) 13-10 8th 2,951 886 381 670 269 (1) Average production calculated on operating days, excludes non-producing days. Includes estimated NGL gas plant recoveries. All production numbers represent sales volumes. (2) Wells listed chronologically by rig release date. (3) Extreme limited entry completion w ith 5 clusters per frac/stage. 13-34-60-24W5 four-well pad Increased stage counts to 80 (50 ball drop and 30 Perf & Plug) on two eastern-most wells directly offsetting 15-10 Cased hole extreme limited entry with 40 stage x 5 clusters = 200 perf clusters on two western-most wells Pad drilling will greatly reduce frac hits (offset frac hits impact gas rate more than field condensate rate) Pad completions with cased hole liners will reduce costs and liner problems/failures Observing performance over the first 90-180 days will be necessary to determine impacts of the increased fracture intensity 7 September 2019
INCREASING CONDENSATE YIELDS Condensate Gas Ratios Significantly Greater in West Bigstone with Frac Design Changes Delphi Bigstone Montney - IP180 CGR vs. IP30 CGR 250 West Type Well - Stabilized CGR Type Well - Stabilized CGR IP180 CGR (bbl/mmcf sales) 200 13-21 150 13-9 15-8 14-9 15-9 14-21 West wells 9-8 16-9 100 16-21 15-21 13-10 12-27 14-27 2-1 16-24 3-26 14-24 10-27 15-24 13-15 13-24 16-18 2-7 13-17 13-30 13-23 14-30 50 16-15 16-27 8-21 15-23 14-11 16-23 15-30 15-11 15-10 11-17 East wells 0 0 50 100 150 200 250 300 350 IP30 CGR (bbl/mmcf sales) Initial Production (IP) Rate Well Performance (1) Delphi Bigstone Montney IP30 IP90 IP180 IP365 Total FCondy Field CGR Total FCondy Field CGR Total FCondy Field CGR Total FCondy Field CGR (boe/d) (bbl/d) (bbl/mmcf) (boe/d) (bbl/d) (bbl/mmcf) (boe/d) (bbl/d) (bbl/mmcf) (boe/d) (bbl/d) (bbl/mmcf) Average West Wells 1,055 588 277 855 415 207 699 311 171 528 213 143 Average East Wells 1,340 440 108 1,127 308 80 927 230 70 699 158 62 Average All Wells 1,227 498 175 1,019 350 131 848 258 105 649 174 86 (1 ) Average production for 2 mile, toe-up, slickwater fraced wells calculated on operating days, excludes non-producing days. Includes estimated NGL gas plant recoveries. All production numbers represent sales volumes. 8 September 2019
MOST RECENT WEST BIGSTONE RESULTS West Bigstone 15-10-60-24W5 West Bigstone 16-10-60-24W5 10,000 10,000 64 stages 64 stages Raw Gas (mcf/d) and Field Condensate (bbl/d) Raw Gas (mcf/d) and Field Condensate (bbl/d) frac hit 1,000 1,000 frac hit 100 100 16-10 Gas 16-10 Field Condy 15-10 Gas 15-10 Field Condy Rich Type Curve Gas Rich Type Curve Field Condy Rich Type Curve Gas Rich Type Curve Field Condy 10 10 0 30 60 90 120 150 180 210 240 270 0 30 60 90 120 150 180 210 240 270 300 330 360 390 420 450 Producing Days Producing Days West Bigstone 02/15-19-59-23W5 West Bigstone 03/16-31-59-23W5 10,000 10,000 50 stages 64 stages Raw Gas (mcf/d) and Field Condensate (bbl/d) Raw Gas (mcf/d) and Field Condensate (bbl/d) 1,000 1,000 100 100 03/16-31 Gas 03/16-31 Field Condy 02/15-19 Gas 02/15-19 Field Condy 10 Rich Type Curve Gas Rich Type Curve Field Condy 10 Rich Type Curve Gas Rich Type Curve Field Condy 0 30 60 90 120 150 180 210 240 270 300 330 360 0 30 60 90 120 150 180 210 240 270 Producing Days Producing Days 9 September 2019
INCREASING NETBACKS Corporate netbacks increase with addition of higher condensate yield wells Impact of Production Composition on IP90 Operating Netback for Bigstone Montney (1) 50.00 IP90 CGR = 207 IP90 CGR IP90 CGR = = 131 40.00 80 % Change Revenue ($/BOE) West vs East Revenue 23% 30.00 $28 Royalty 23% $22 $19 Operating costs (15%) 20.00 Transportation (5%) $6 $6 $6 Netback 46% 10.00 $7 $7 $6 $2 $2 $2 - East All Wells West Royalties Opcosts Transportation Operating netback (1) Based on US$ 60 WTI, US$2.90 NYMEX gas and 2019 estimated field differentials, operating costs and transportation costs per unit for each product stream and average royalty rates. 10 September 2019
BIGSTONE MONTNEY GROWTH Montney asset growth funded largely Montney Production Growth through cash flow (47%) and non-core asset dispositions (28%) 10,000 Liquids CAGR 48% Nat. Gas CAGR 36% Life-to-date (LTD) capital includes 8,000 $605 mm DCE&T 6,000 Boe/d $43 mm land / acquisitions 4,000 148 gross sections of land acquired 2,000 $100 mm LTD facility infrastructure build out 0 Ownership in 100+ mmcf/d field gathering and 2012 2013 2014 2015 2016 2017 2018 plant processing capacity Gas Liquids Non-Montney Funding Bigstone Montney Source of Funding Cumulative Debt $600 10,000 14% $605 million Proceeds $500 8,000 LTD Capital Equity $ millions $400 11% 6,000 $300 4,000 $200 2,000 $100 Cash Dispositions $0 0 Flow 28% 2012 2013 2014 2015 2016 2017 2018 47% Cum Capital Cum Proceeds Production 11 September 2019
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