January 2018 HIGH-MARGIN, LIQUIDS-RICH PRODUCTION IN THE WORLD- CLASS MONTNEY BIGSTONE REGION

January 2018 HIGH-MARGIN, LIQUIDS-RICH PRODUCTION IN THE WORLD- CLASS MONTNEY BIGSTONE REGION

WHY OWN DELPHI. Pure play MONTNEY E&P company with WORLD CLASS ASSETS: Robust well economics driven by: High condensate rates/stable condensate ratios Attractive capital costs and efficiencies Increasing netbacks and margins Owned infrastructure with available capacity Premium market access avoiding the AECO/Station 2 price crisis Excess Chicago/Alliance firm service providing arbitrage opportunity Superior hedge book mitigating commodity price volatility Solid balance sheet January 2018 2

BIGSTONE SOUTHERN END OF PROLIFIC LIQUIDS RICH MONTNEY TREND Ticker Symbol CORPORATE INFORMATION TSX:DEE Basic Shares Outstanding (mm) 185.5 Market Capitalization (mm) (1) $200.4 Net Bank Debt (2) / Credit Facility (mm) $22.7/ $95.0 5 Year Senior Secured Notes (mm) $90.0 (1) As at January 15, 2018. (2) Bank debt plus working capital deficiency as at September 30, 2017. Bigstone Montney Wells Drilled Grande Prairie Bigstone Montney Edmonton Calgary 18 16 14 12 10 8 6 4 2 0 4 6 8 6 6 2012 2013 2014 2015 2016 2017 17 + 2 wells of 2018 program started drilling January 2018 3

2017 OPERATIONAL HIGHLIGHTS Delineation success Achieved significant production and cash flow growth Field condensate growth of approximately 67% is driver of economic success 2017 cash flow to meet guidance Q4/17 run-rate cash flow Dec/17 exit rate excludes 500 boe/d of curtailed Montney production Frac design innovation changing type curve characteristics More condensate less nat gas Lower IP30 lower decline profiles Focus on parent/child well interference Completed 17 well drilling program and started on 2018 program early Approximately $6 million of 2018 program spent in Dec/17 2017 Current Estimate Guidance Average Annual Production (boe/d) 8,305 8,600 8,900 December Exit Production (boe/d) 9,950 11,000 Gross Well Count (Net) 17 (11.0) 17 (11.0) Gross Well Count On Production (Net) 14 (9.0) 14 (9.0) - 15 (9.7) Capital Program ($ million) (1) $115 $105.0 - $110.0 Funds from Operations ( FFO ) ($ million) December 31, 2017 Net Bank Debt ($ million) Q4/17E Q4/16 Variance Corp Production (boe/d) 9,200 7,127 +29% Field Condensate (bbl/d) 2,220 1,330 +67% NGL s (bbl/d) 1,360 1,132 +20% Natural Gas (mmcf/d) 33.7 28.0 +20% Strong return on capital, increased cash flow and positive momentum heading into 2018 despite lower than expected 2017 production - $35.0 - $38.0 - $37.0 - $42.0 Total Debt / Q4 FFO (annualized) - 2.2 2.4 (1) Estimate includes $6 million of 2018 program spent in 2017 January 2018 4

GROWING THE DOMINANT LAND POSITION Largest Land Position at Bigstone Continue to identify and pursue additional consolidation opportunities Added 23.5 sections (100% W.I.) of Montney Rights growing land base to 168.5 gross (111.1 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. Refer to disclaimer for further details. January 2018 5

INFRASTRUCTURE LARGELY IN PLACE Alliance/TCPL Pembina SemCams KA/K3 To TCPL Alliance/TCPL Pembina DEE Water Disposal 6,000 bpd capacity REPSOL Edson Alliance/TCPL Alliance/TCPL Pembina SemCams K3 January 2018 6

DELINEATING THE LARGE LAND POSITION 14 new wells on-stream in 2017 1 new well recently completed 2 new wells waiting on completion Development & Delineation 100% drilling success on 46 DEE wells 17 well drilling program in 2017 Early start to 2018 program Three Montney layers proven productive Industry active offsetting DEE WEST BIGSTONE EAST BIGSTONE West Bigstone D3 16-12 and 13-7 well results are positive D2 D2 Multiple layers to drill D1 D1 Natural gas is low H2S/sweet C Condensate yields increasing C B1 B1 100% South Montney Lands 2017 delineation drilling program has validated Delphi s Bigstone Montney s significant value potential 13-10 and 15-19 results are outstanding Industry de-risking offsetting lands January 2018 7

RECENT WELL RESULTS YIELD EVEN GREATER MARGINS Condensate Gas Ratios Improving with Frac Design Changes Initial Production (IP) Rate Well Performance (1) Frac Design Generation IP30 IP90 IP180 IP365 Total Sales Field CGR Total Sales Field CGR Total Sales Field CGR Total Sales Field CGR (boe/d) (bbl/mmcf) (boe/d) (bbl/mmcf) (boe/d) (bbl/mmcf) (boe/d) (bbl/mmcf) Average 1st Gen 1,213 48 807 36 557 33 397 31 Average 2nd Gen 1,398 86 1,160 72 946 65 719 58 Average 3rd, 4th & 5th Gen 1,143 163 1,005 110 880 98 693 77 Average west 16-12 & 13-7 wells 735 272 (1) Average production calculated on operating days, excludes non-producing days. Includes estimated NGL gas plant recoveries. All production numbers represent sales volumes. January 2018 8

INCREASING NETBACKS Corporate netbacks increase with addition of higher condensate yield wells Impact of Production Composition on Operating Netback for Bigstone Montney(1) % Change 16-12/13-7 versus Gen 1 Revenue 48% Royalty 48% Operating costs (24%) Transportation (10%) Netback 112% 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 (1) Based on US$ 60 WTI, US$2.80 NYMEX gas, 2018 estimated field differentials, operating costs and transportation costs per unit for each product stream and average royalty rates. January 2018 9

Gas (mcf/d) & Field Condensate (bbl/d) NEW 5 TH GENERATION FRAC DESIGN IMPROVING PERFORMANCE 10,000 Direct offset comparison of 5 th to 3 rd Generation Frac 1,000 IP30: Gas and Plant NGL -373 boe/d Field Condensate -76 boe/d Total -449 boe/d but higher production after IP30 Increased Condensate Rates and Yields Shallower initial decline 100 13-15-60-23W5 Gas 14-15-60-23W5 Gas 3 rd Gen 5 th Gen 13-15-60-23W5 Field Condensate 14-15-60-23W5 Field Condensate 10 0 30 60 90 120 150 180 Days on Production 15-19-59-23W5 delineation well using 5 th Generation Frac design tested 7.6 mmcf/d raw gas and 1,438 bbl/d field condensate. January 2018 10

IMPROVED PARENT / CHILD WELL MANAGEMENT 10,000 1,000 Delphi 13-9-60-23W5 Montney Offset Frac Well Intervention Initial production performance of 13-9 (and other pad wells) was below expectations 100 10 Field Condensate up 115% Natural Gas up 54% 14 days 18 days Field Condensate (bbl/d) Gas (mcf/d) CGR (bbl/mmcf) 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 expectations January 2018 11

WESTERN-MOST WELLS: HIGHEST CONDENSATE YIELD TO DATE 10,000 Delphi 16-12-60-24W5 Montney 10,000 Delphi 13-7-60-23W5 Montney 1,000 1,000 100 100 Highest initial condensate yield Shallower initial decline 10 Field Condensate (bbl/d) Gas (mcf/d) CGR (bbl/mmcf) 10 Field Condensate (bbl/d) Gas (mcf/d) CGR (bbl/mmcf) Average IP30 field condensate yield of 272 bbl/mmcf sales Both wells completed with 40-stages and ~1,350 lb/ft of sand (4 th Generation) 6 th Generation Frac will consist of 65 distinct frac stages and over 1,800 lb/ft of sand Recently drilled 16-10-60-24W5 will be the first to implement this design January 2018 12

SECURE MARKET ACCESS FOR GROWTH Delphi/Alliance Full Path Service to Chicago Contracted Transportation Service (mmcf/d) 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 activity TCPL 24 mmcf/d firm service Low cost service for growth beyond 2018 (1) Delphi captures the value of excess Alliance firm service either by assigning it to 3 rd parties at a premium above cost or by using it to transport 3 rd party natural gas purchased in Alberta and sold in Chicago to generate marketing income. January 2018 13

GAS MARKETING IN 2018 100% SHELTERED FROM AECO CARNAGE Over 90% of natural gas sold in Chicago generating significantly higher netback pricing than AECO. Approximately 63% of Chicago sales volumes are hedged with NYMEX swaps at an average price of US$ 3.08 (C$3.85) per mmbtu (2). Minimal AECO exposure is hedged through premiums earned on assignment of excess Alliance firm service. Delphi Cash Flow Sensitivity to AECO-Chicago Basis Increase in spread between AECO and Chicago US$0.20 / mmbtu Change in AECO revenue ($ mm/year) Change in premiums earned on excess Alliance service (3) ($mm/year) Change in cash flow ($mm/year) (0.3) 0.5 0.2 Worsening AECO-Chicago basis increases Delphi cash flow in 2018 (1) Estimates are based on average daily gas sales of 38 mmcf/d. (2) Based on CAD/US FX of 1.25. Comprised of 5,250 mmbtu/d at US$2.75 per mmbtu and 14,583 mmbtu/d at C$4.00 mmbtu. The Chicago- NYMEX basis is fixed at an average of US$(0.21) per mmbtu on 16,000 mmbtu/d. (3) Based on an average of 8 mmcf/d of excess firm service on Alliance. (4) Assumes that Delphi captures 75% of arbitrage between Chicago and AECO. January 2018 14

CONTRACTED ALLIANCE SERVICE IS A VALUABLE ASSET Delphi s Alliance service worth > $40 million The undiscounted value of the arbitrage between AECO and Chicago netback prices available through Delphi s Alliance service is approximately $40 million over the next 4 years (1). Delphi expects to generate up to $7 million from excess Alliance service in 2018 The estimated cash flow generated through premiums on assignment and marketing activity related to excess Alliance service in 2018 is expected to be up to $7 million. Arbitrage between AECO and Chicago Available through Delphi s Alliance Transportation Service (1) Value of AECO-Chicago Arbitrage Available through Delphi s Alliance Transportation Service (1) (1) Based on strip pricing as of January 12, 2018 January 2018 15

($ mm's) (boe/d) ENTERING 2018 WITH OPERATIONAL MOMENTUM Expect 2018 budget to be released in mid-february 2018 Planning Scenarios Production data from 2017 delineation drilling important input for 2018 planning and forecasting 2018 Annual Production Current planning scenarios for 2018 contemplate a modest outspend of cash flow in 2018 15,000 10,000 5,000 13% 29% 37% 40% 30% 20% 10% Hedge book and Chicago/Alliance gas marketing continues to mitigate commodity price volatility - 50 55 60 WTI (US$/bbl) 0% Early start to 2018 drilling program in Dec/17 Production Growth (YoY %) 5 new wells expected on production in 1H/18 2018 CAPEX and Cash Flow 2 5 DUC s potentially ready for completion into Q3/18 100 200% Phase 1 Amine plant scheduled for Q2/18 start-up 80 60 40 124% 105% 121% 150% 100% 20 50% Excess Alliance-Chicago transportation firm service provides arbitrage to AECO/Station 2 price weakness generating additional revenue 0 50 55 60 WTI (US$/bbl) CAPEX CF CAPEX (% of CF) 0% January 2018 16

2018 AND BEYOND MAINTAINING KEY VALUES World Class Montney Asset Delineation drilling in 2017 has validated Delphi s Bigstone Montney s significant value potential Superior condensate rich well performance yielding top decile capital efficiencies Market Access and Hedging Strategy Secured firm service with Alliance to access Chicago gas market for stronger pricing Excess firm service generating additional cash flow on AECO/Station 2 price weakness Hedge book mitigates commodity price volatility Operational Performance Continued new well innovations resulting in increasing condensate yields and operating margin growth Operating efficiency gains coming in 2018 with increased pad drilling Infrastructure and Operational Control Growth utilizing existing major infrastructure, with minimal capital requirements Operatorship with ownership in strategic infrastructure with strong industry partner relationship Land Inventory Dominant land position with 168.5 sections of Montney opportunity with 19+ years of drilling inventory Continuing to pursue consolidation opportunities within our core land base January 2018 17

FORWARD-LOOKING STATEMENTS AND IMPORTANT NOTES The presentation contains forward-looking statements and forward-looking information within the meaning of applicable Canadian securities laws. These statements relate to future events or the Company s future performance and are based upon the Company s internal assumptions and expectations. All statements other than statements of present or historical fact are forward-looking statements. Forward-looking statements are often, but not always, identified by the use of any of the words expect, anticipate, continue, estimate, may, will, should, believe, "intends, forecast, plans, guidance, budget and similar expressions. More particularly and without limitation, this presentation contains forward-looking statements and information relating to petroleum and natural gas production estimates and weighting, projected crude oil and natural gas prices, future exchange rates, expectations as to royalty rates, expectations as to transportation and operating costs, expectations as to general and administrative costs and interest expense, expectations as to capital expenditures and net debt, planned capital spending, future liquidity and Delphi s ability to fund ongoing capital requirements through operating cash flows and its credit facilities, supply and demand fundamentals for oil and gas commodities, timing and success of development and exploitation activities, cash availability for the financing of capital expenditures, access to third-party infrastructure, treatment under governmental regulatory regimes and tax laws and future environmental regulations. Furthermore, statements relating to reserves are deemed to be forward-looking statements as they involve the implied assessment, based on certain estimates and assumptions that the reserves described can be profitable in the future. The forward-looking statements and information contained in this presentation are based on certain key expectations and assumptions made by Delphi. The following are certain material assumptions on which the forward-looking statements and information contained in this presentation are based: the stability of the global and national economic environment, the stability of and commercial acceptability of tax, royalty and regulatory regimes applicable to Delphi, exploitation and development activities being consistent with management s expectations, production levels of Delphi being consistent with management s expectations, the absence of significant project delays, the stability of oil and gas prices, the absence of significant fluctuations in foreign exchange rates and interest rates, the stability of costs of oil and gas development and production in Western Canada, including operating costs, the timing and size of development plans and capital expenditures, availability of third party infrastructure for transportation, processing or marketing of oil and natural gas volumes, prices and availability of oilfield services and equipment being consistent with management s expectations, the availability of, and competition for, among other things, pipeline capacity, skilled personnel and drilling and related services and equipment, results of development and exploitation activities that are consistent with management s expectations, weather affecting Delphi s ability to develop and produce as expected, contracted parties providing goods and services on the agreed timeframes, Delphi s ability to manage environmental risks and hazards and the cost of complying with environmental regulations, the accuracy of operating cost estimates, the accurate estimation of oil and gas reserves, future exploitation, development and production results and Delphi s ability to market oil and natural gas successfully to current and new customers. Additionally, estimates as to expected average annual production rates assume that no unexpected outages occur in the infrastructure that the Company relies on to produce its wells, that existing wells continue to meet production expectations and any future wells scheduled to come on in the coming year meet timing and production expectations. Commodity prices used in the determination of forecast revenues are based upon general economic conditions, commodity supply and demand forecasts and publicly available price forecasts. The Company continually monitors its forecast assumptions to ensure the stakeholders are informed of material variances from previously communicated expectations. Financial outlook information contained in this presentation about prospective results of operations, financial position or cash flows is based on assumptions about future events, including economic conditions and proposed courses of action, based on management s assessment of the relevant information currently available. Readers are cautioned that such financial outlook information contained in this presentation should not be used for purposes other than for which it is disclosed. Although the Company believes that the expectations reflected in such forward-looking statements and information are reasonable, it can give no assurance that such expectations will prove to be correct and such forward-looking statements should not be unduly relied upon. Since forward-looking statements and information address future events and conditions, by their very nature they involve inherent known and unknown risks and uncertainties. Delphi s actual results, performance or achievements could differ materially from those expressed in, or implied by, these forward-looking statements and, accordingly, no assurance can be given that any of the events anticipated by the forward-looking statements will transpire or occur, or if any of them do so, what benefits Delphi will derive therefrom. Should one or more of these risks or uncertainties materialize, or should assumptions underlying forward-looking statements prove incorrect, actual results may vary materially from those currently anticipated due to a number of factors and risks. These include, but are not limited to, the risks associated with the oil and gas industry in general such as operational risks in development, exploration and production, delays or changes in plans with respect to exploration or development projects or capital expenditures, the uncertainty of estimates and projections relating to production rates, costs and expenses, commodity price and exchange rate fluctuations, marketing and transportation, environmental risks, competition from others for scarce resources, the ability to access sufficient capital from internal and external sources, changes in governmental regulation of the oil and gas industry and changes in tax, royalty and environmental legislation. Additional information on these and other factors that could affect the Company s operations or financial results are included in the Company s most recent Annual Information Form and other reports on file with the applicable securities regulatory authorities and may be accessed through the SEDAR website (www.sedar.com). Readers are cautioned that the foregoing list of factors is not exhaustive. Furthermore, the forward-looking statements contained in this presentation are made as of the date of this presentation for the purpose of providing the readers with the Company s expectations for the coming year. The forward-looking statements and information may not be appropriate for other purposes. Delphi undertakes no obligation to update publicly or revise any forward-looking statements or information, whether as a result of new information, future events or otherwise, unless so required by applicable securities laws. The forward-looking statements contained in this presentation are expressly qualified in their entirety by this cautionary statement. January 2018 18

FORWARD-LOOKING STATEMENTS AND IMPORTANT NOTES The following criteria reflects Montney economic modeling assumptions herein the presentation; 1. Strip pricing for 5 years then escalated at 2%/yr thereafter. 2018 prices: Henry Hub $2.90/mmbtu US, $3.60/mmbtu CDN; WTI $62.39/bbl USD; C5 $79.46/bbl CDN. 2019 Prices: Henry Hub $2.81/mmbtu US, $3.49/mmbtu CDN; WTI $57.96/bbl USD; C5 $71.93/bbl CDN. 2. Type Well stabilized field condensate beyond month six is 46 bbl/mmcf sales; Rich Type Well stabilized field condensate production beyond month one is 115 bbl/mmcf sales. 3. C3: Propane, C4: Butane, C5: Pentane. Gas plant recovered natural gas liquids estimated at 44 bbl/mmcf sales. 4. Type Well reserves and production performance are internal management estimates and were prepared by a qualified reserves evaluator in accordance with the COGE Handbook. Delphi's first 18 horizontal toe up Montney wells at East Bigstone with at least 30 stage fracs were time normalized, averaged and used to determine a proved plus probable reserve estimate. 5. Rich Type Well Shale gas reserve assumptions are based on year end 2015 GLJ proved plus probable ultimate recoverable assignment of 3.9 bcf for the 102/15-21-60-23W5 well which is the western most horizontal Montney well brought on production at east Bigstone by Delphi as of December 31, 2015. 102/15-21 has a life to date field condensate to gas ratio (CGR) of 88 bbl/mmcf sales since coming on production in February 2014. Reserve estimates include estimated gas plant recovered natural gas liquids of 44 bbl/mmcf sales. 6. Reserve and production estimates are used for illustrative purposes and internal corporate planning and may not reflect the actual performance of future wells. Economics are half cycle and include target capital to drill, complete, equip and tie-in. No costs for land, central facilities, field gathering infrastructure, corporate costs, etc. are included. For further details on the completion and clean-up test results of the 15-19-59-23W5 well, please see the Company s press release dated January 16, 2018. This presentation discloses the Company s future potential drilling opportunities. Unbooked locations are internal estimates based on the Company s prospective acreage and an assumption as to the number of wells that can be drilled per section based on industry practice and internal review. Unbooked locations do not have attributed reserves or resources (including contingent and prospective). Unbooked locations have been identified by management as an estimation of the Company s multi-year drilling activities based on evaluation of applicable geologic, seismic, engineering, production and reserves information. There is no certainty that the Company will drill all unbooked drilling locations and if drilled there is no certainty that such locations will result in additional oil and gas reserves, resources or production. The drilling locations on which the Company will actually drill wells, including the number and timing thereof is ultimately dependent upon the availability of funding, regulatory approvals, seasonal restrictions, oil and natural gas prices, costs, actual drilling results, additional reservoir information that is obtained and other factors. While a certain number of the unbooked drilling locations have been derisked by drilling existing wells in relative close proximity to such unbooked drilling locations, the majority of other unbooked drilling locations are farther away from existing wells where management has less information about the characteristics of the reservoir and therefore there is more uncertainty whether wells will be drilled in such locations and if drilled there is more uncertainty that such wells will result in additional oil and gas reserves, resources or production. January 2018 19

APPENDIX January 2018 20

INDIVIDUAL MONTNEY WELL DATA 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) Average 1st Gen Frac 2,668 20 1,213 48 807 36 557 33 397 31 Average 2nd Gen Frac 2,572 30 1,398 86 1,160 72 946 65 719 58 14-30 3rd 2,729 37 1,840 78 1,407 66 1,112 55 805 57 14-24 (3) 3rd 2,602 37 1,119 132 976 92 792 76 585 65 14-27 (3) 3rd 2,887 37 1,414 140 1,280 97 1,082 83 835 70 13-21 (3) 3rd 2,781 37 1,204 252 1,077 194 962 166 679 172 15-23 3rd 2,865 37 1,153 93 909 66 779 54 612 47 14-11 3rd 2,846 42 1,212 106 1,028 65 870 53 642 49 16-09 4th 2,855 40 1,161 121 849 108 685 106 14-21 3rd 2,788 40 1,606 180 1,258 145 968 128 16-21 3rd 2,858 40 1,968 134 1,541 102 1,258 103 15-8 4th 2,740 40 1,243 216 1,118 185 890 152 15-11 3rd 2,866 40 1,375 80 1,178 54 929 46 13-15 3rd 2,891 40 1,579 106 1,205 85 943 73 15-09 (3) 3rd 2,864 40 756 196 625 149 504 137 13-09 (3) 4th 2,813 40 895 185 668 164 13-17 (3) 3rd 2,876 40 562 112 575 69 14-09 (3) 4th 2,863 40 865 213 677 160 542 139 16-18 (3) 4th 2,881 40 500 182 605 87 13-10 4th 2,848 39 1,161 167 1,118 101 9-21 (3) 4th 2,841 40 waiting on IP30 16-12 4th 2,859 39 717 300 9-8 4th 2,574 38 941 202 13-7 4th 2,847 40 753 245 14-15 5th 2,879 49 1,130 139 15-19 5th 2,862 50 completed 14-10 5th 2,856 50 waiting on completion 16-07 5th 2,853 50 waiting on completion Average 3rd, 4th & 5th Gen Frac 2,821 39 1143 163 1005 110 880 98 693 77 (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) Initial production restricted. January 2018 21

MONTNEY ECONOMIC MODEL Bigstone Montney Toe Up Two Section Horizontal Hypothetical Type Wells 30+ stage Slickwater Completion DEE Type Well Type Well Rich Type Well Payout yrs 1.7 1.1 IRR % 57% 105% NPV 10 MM$ $5.6 $11.7 PI 1.7 2.5 F&D $/boe $7.21 $6.21 Target Capital D,C,E&TI MM$ $8.0 $8.0 Initial Sales Production (IP30 - first 30 day average) Gas mmcf/d 5.1 3.6 Field Condensate (2) bbl/mmcf 97 183 Total Liquids (C3+) (2,3) bbl/mmcf 137 223 Total Liquids (C3+) (2,3) bbl/d 698 806 Total IP30 boe/d 1,550 1,408 IP365 (first 365 day average) Gas mmcf/d 2.9 2.2 Field Condensate (2) bbl/mmcf sales 62 125 Total Liquids (C3+) (2,3) bbl/mmcf sales 101 165 Total Liquids (C3+) (2,3) bbl/d 296 360 Total IP365 boe/d 783 724 Reserves (sales) Gas bcf 4.3 4.0 Liquids (C3+) (2,3) mmbbl 0.4 0.6 Total mmboe 1.1 1.3 Rich Type Well 13-21 Yield 2.5x Type Well at 100 bbl/mmcf Full cycle (including $4.00 per boe of G&A and interest costs) IRR for the Type Well and the Rich Type Well are 32% and 76% respectively. Note: See Montney Economic Model Assumptions in the Forward Looking Statement and Important Notes January 2018 22

PROVEN RISK MANAGEMENT PROGRAM Consistent Hedge Performance Majority of near term production is hedged Event driven natural gas hedging strategy with a long term view of relatively balanced supply & demand; Strategy is proven and repeatable over 2-4 year peak to trough event cycles Risk management contracts generally put in place over a 12-48 month period Over an 11 year period risk management program has: Realized $113 million in hedging gains Increased revenues by 9% Increased cash flow by 20% Added $3.65/boe to netback Commodity Hedges $35 $30 $25 $20 $15 $10 $5 $0 -$5 -$10 -$15 Hedging Gains/Losses ($millions) Natural gas price spike in 2008 Q1 2018 Q2 2018 Q3 2018 Q4 2018 2019 Natural gas (mcf/d) 20.0 21.0 21.0 17.4 7.2 Average hedge price (C$/mcf) 3.86 3.84 3.84 3.86 3.90 Crude oil (bbl/d) 2,256 2,500 2,100 2,100 600 Average hedge price (C$/bbl) 70.50 71.20 72.41 72.41 70.13 Steady decline of natural gas prices from 2009 to 2013 Collapse of natural gas and crude oil prices 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017E Cold winter lifting natural gas prices in 2014 January 2018 23

2300, 333 7 th Avenue SW Calgary, Alberta T2P 2Z1 P (403) 265-6171 F (403) 265-6207 info@delphienergy.ca www.delphienergy.ca January 2018 24