HIGH-MARGIN, LIQUIDS-RICH PRODUCTION IN …

1 april 2018 HIGH-MARGIN, LIQUIDS-RICHPRODUCTION IN THE WORLD-CLASS MONTNEY BIGSTONEREGIONWHYOWN : Robustwelleconomicsdrivenby: Highcondensaterates/stablecondensaterati os Attractivecapitalcostsandefficiencies Increasingnetbacksandmargins Ownedinfrastructurewithavailablecapacity PremiummarketaccessavoidingtheAECO/Stati on2pricecrisis ExcessChicago/Alliancefirmserviceprovidi ngarbitrageopportunity Superiorhedgebookmitigatingcommoditypric evolatility SolidbalancesheetApril 20182 BIGSTONE SOUTHERN END OF PROLIFIC LIQUIDS RICH MONTNEY TRENDA pril 20183 Grande PrairieBigstone MontneyEdmontonCalgaryCORPORATEINFORMATI ONT ickerSymbolTSX:DEEB asicShares Outstanding (mm) (mm)(1)$ Bank Debt (2)/Credit Facility (mm)$ $ Year Senior Secured Notes (mm)(3)$ PRODUCTION Growth(1)As at March 6, 2018 .

2 (2)Bank debt plus working capital deficiency as at December 31, 2017.(3)Face value02000400060008000100002013201420152 01620171H2018 Boe/dGasLiquidsNon-Montney2018 GUIDANCE FOR FIRST HALF 20184 april 2018 2018 capital program supported by significant PRODUCTION and cash flow growth through 2017 Condensate growth of 77% in Q4/17 over Q4/16 Cash netbacks in Q4/17 29% greater than Q4/16 Delineation drilling success sets up multiple options for ultra-rich condensate locations in 2018 and beyond PRODUCTION data from 2017 drilling important input for 2H/18 planning First Half 2018 capital program 5 to 7 new wells expected on PRODUCTION in 1H/18 depending on spring breakup timing 1H/18 forecast takes into account PRODUCTION downtime for new well completions and amine plant construction/commissioning Phase 1 Amine plant scheduled for Q2/18

3 Start-up Second Half 2018 capital program expected in late Q2/18 Strong return on capital, increased cash flow largely driven by continued condensate PRODUCTION growth2018 First Half GuidanceNet Capital Program ($ million)$38 -$45 Gross Well Count Drilled (net) 4 ( )Gross Well Count On PRODUCTION (net)5 ( ) 7 ( ) 2018 First Half Guidance2017 First Half Actuals% ChangeAverage PRODUCTION (boe/d)9,800 10,2007,33636 Natural Gas (mmcf/d) Condensate (bbls/d)2,450 2,5501,73844 NGL s (bbls/d)1,470 1,5301,16029 Percent Liquids (%)4040-Adjusted Funds Flow ( AFF )$ -$ $ Netback (per boe, excluding hedges)$ $ Debt (1) (2)$ $ $ Debt / Quarterly AFF (annualized) (1) Based on WTI crude oil price of $62 per barrel, NYMEX Henry Hub natural gas price of $ FX of CAD/USD.

4 (2) Net debt is defined as the sum of bank debt, senior secured notes and the long term portion of unutilized take-or-pay contract plus (minus) the working capital deficit (surplus) excluding the current portion of the fair value of the financial THE DOMINANT LAND POSITION Continue to identify and pursue additional consolidation opportunities Montney land base has grown to gross sections ( net) Significant land position allows for efficient operations, control over infrastructure and scalable development 19+ year drilling inventory* on approximately 128 of 147 undeveloped sections: 400+ Extended Reach HZ locations equivalent to 800+ 1 mile industry locations 19 years of drilling inventory assuming a 3 rig (21 well/year) program* Based on 4 to 6 laterals per section and 1 to 2 layers across the 128 sections, increasing in well density from NE to SW.

5 Refer to disclaimer for further 20185 Largest Land Position at BigstoneApril 20186 INFRASTRUCTURE LARGELY IN PLACEA lliance/TCPLP embinaSemCamsKA/K3 REPSOL Edson Alliance/TCPLA lliance/TCPL PembinaSemCamsK3To TCPLA lliance/TCPL PembinaDEE Water Disposal6,000 bpd capacityDELINEATING THE LARGE LAND POSITIONA pril 20187 15 new wells on-stream in 2017 7 new wells completed in 1H 20187 WEST BIGSTONEEAST BIGSTONED3D2D1B1CD1CD2B1 Development & Delineation100% South MontneyLands 100% drilling success on 52 DEE wells 4 wells drilled in 1H/ 2018 5 7 wells on PRODUCTION in 1H/ 2018 Three Montneylayers proven productive Industry active offsetting DEE 13-10 and 14-10 results are positive Industry de-risking offsetting lands Ultra-rich Condensate yields Multiple layers to drill Natural gas is low H2S/sweet Condensate yields increasingWest BigstoneDelineation drilling program has validated Delphi s Bigstone Montney ssignificant value potentialRECENT WELL RESULTS YIELD EVEN GREATER MARGINSA pril 20188 Condensate Gas Ratios

6 Improving with FracDesign Changes Initial PRODUCTION (IP) Rate Well Performance(1)Frac Design GenerationTotal SalesField CGRT otal SalesField CGRT otal SalesField CGRT otal SalesField CGR(boe/d)(bbl/mmcf)(boe/d)(bbl/mmcf)(bo e/d)(bbl/mmcf)(boe/d)(bbl/mmcf)Average 1st Gen1,21348807365573339731 Average 2nd Gen1,398861,160729466571958 Average 3rd, 4th & 5th Gen1,133 162 966 120 816 97 696 84 Average west 16-12 & 13-7 wells735272635203(1) Average PRODUCTION calculated on operating days, excludes non-producing days. Includes estimated NGL gas plant recoveries. All PRODUCTION numbers represent sales NETBACKSA pril 20189 Condensate on a BOE basis Higher realized price than natural gas and NGLs Lower op cost than natural gas and NGLs Lower transportation cost than natural gas% Change16-12/13-7 versus Gen 1 Revenue48%Royalty48%Operating costs(24%)Transportation(10%)Netback112% (1)Based on US$ 60 WTI, US$ NYMEX gas, 2018 estimated field differentials, operating costs and transportation costs per unit for eachproduct stream and average royalty rates.

7 Corporate netbacks increase with addition of higher condensate yield wellsImpact of PRODUCTION Composition on Operating Netback for Bigstone Montney(1)NETBACK COMPARISON MONTNEY PRODUCERSA pril 201810 Condensate yields, total liquids content and operating netbacks are among the highest Operating netbacks continue to increase as:oFocus on West Bigstoneproduction growth where liquids yields and netbacks are 40 50% higher than corporate averageoAddition of Amine sweetening reduces volumes requiring third-party processing and lowers overall operating costsoLegacy PRODUCTION (currently 10% of PRODUCTION and less than 2% of operating income) declines as a percent of total production0%20%40%60% - CorpDEEM ontneyDEEWestBigstoneVIINVAKELCRBIRSRXAA VR evenue excluding hedges and other income ($/boe)Operating Netback Fourth Quarter 2017 Operating netbackRoyaltiesOperatingTransportation% Liquids (Total)% CondensateWESTERN-MOST WELLS.

8 HIGHEST CONDENSATE YIELD TO DATEA pril 201811 Average IP90 field condensate yield of 203 bbl/mmcf sales Both wells completed with 40-stages and ~1,350 lb/ftof sand (4thGeneration) 6thGeneration Frac will consist of 65 distinct frac stages and over 1,800 lb/ftof sand Recently drilled 16-10-60-24W5will be the first to implement this design Highest initial condensate yield Shallower initial declineIMPROVED PARENT / CHILD WELL MANAGEMENTA pril 201812 Initial PRODUCTION performance of 13-9 (and other pad wells) was below expectations It was further impacted by an offset frac in October A partial mill/clean-out of the horizontal has brought PRODUCTION back in-line with expectationsOffset FracWell Intervention Field Condensate up 66% Natural Gas up 50%14 days18 daysSECURE MARKET ACCESS FOR GROWTHA pril 201813 Alliance 57 mmcf/d of firm and priority interruptible service Access to premium pricing via Chicago City Gate Approximately 23 mmcf/d in excess of requirements for 2018 Delphi captures value of excess service through assignment at a premium or marketing activityTCPL 24 mmcf/d firm service Low cost service for growth beyond 2018 Delphi/AllianceFull Path Service to Chicago(1)

9 Delphi captures the value of excess Alliance firm service either by assigning it to 3rdparties at a premium above cost or by using it to transport 3rdparty natural gas purchased in Alberta/BC and sold in Chicago to generate marketing Transportation Service (mmcf/d)GAS MARKETING IN 2018 100%SHELTERED FROM AECO CARNAGEA pril 201814(1)Estimates are based on average daily gas sales of 38 mmcf/d.(2)Based on CAD/US FX of Comprised of 5,250 mmbtu/d at US$ per mmbtuand 14,583 mmbtu/d at C$ mmbtu. The Chicago-NYMEX basis is fixed at an average of US$( ) per mmbtuon 19,014 mmbtu/d.(3)Based on an average of 12 mmcf/d of excess firmservice on Alliance.(4)Assumes that Delphi captures 75% of arbitrage between Chicago and AECO. Over 90% of natural gas sold in Chicago generating significantly higher netback pricing than AECO.

10 Approximately 60% of Chicago sales volumes are hedged with NYMEX swaps at an average price of US$ (C$ ) per mmbtu(2). Minimal AECO exposure is hedged through premiums earned on assignment of excess Alliance firm in spread between AECO and Chicago ChangeinAECO revenue ($mm/year)Changein premiums earned on excess Alliance service(3)($mm/year)Change in cashflow($mm/year)US$ / mmbtu( ) Cash Flow Sensitivity to AECO-Chicago BasisWorsening AECO-Chicago basis increases Delphi cash flow in 2018 CONTRACTED ALLIANCE SERVICE IS A VALUABLE ASSETA pril 201815(1)Value of arbitrage between AECO and Chicago available through all of Delphi s Alliance service(2)Based on strip pricing as of January 12, 2018 The undiscounted value of the arbitrage between AECO and Chicago netback prices available through all of Delphi s Alliance service is approximately $40 million over the next 4 years(2).