September 28, 2018 SEPTEMBER PRESENTATION

September 28, 2018 SEPTEMBER PRESENTATION

BIGSTONE PROLIFIC, LIQUIDS RICH MONTNEY Pure play MONTNEY E&P company with WORLD CLASS ASSETS: Successful delineation drilling to the west and south Growing condensate production and high stable yields Integration of owned infrastructure leading to lower operating costs Alliance / Chicago natural gas market access Grande Prairie Bigstone Montney Edmonton Calgary September 2018 2

2018 GUIDANCE FOR SECOND HALF 2018 2018 capital program supported by significant production and cash flow growth through 2017 Condensate growth of 16% in Q2/18 over Q1/18 Cash netbacks in Q2/18 14% greater than Q1/18 Delineation drilling success sets up multiple options for ultra-rich condensate locations in 2018 and beyond First Half 2018 capital program 7 new wells on production in 1H/18 Phase 1 Amine plant on-stream Second Half 2018 capital program 4 new wells on production in 2H/18 2018 Second Half Guidance (1) 2018 Full Year Guidance Net capital program ($ million) $29 - $33 $75 - $80 Well count drilled 4 (2.6 net) 5 (3.3 net) 8 (5.2 net) Well count on production 4 (2.6 net) 11 (7.2 net) Average production (boe/d) 10,000 10,200 10,000 10,200 Natural gas (mmcf/d) 36.8 37.2 36.0 36.5 Field condensate (bbls/d) 2,500 2,600 2,600 2,650 NGL s (bbls/d) 1,400 1,450 1,450 1,500 Percent liquids (%) 40 41 40 Adjusted funds flow ( AFF ) ($ $25 - $27 $50 - $54 million) Net debt (2) $160 $166 $160 $166 Net debt / AFF (annualized) 3.1 3.1 Strong return on capital, increased cash flow largely driven by continued condensate production growth 2018 Q4 Guidance 2017 Q4 Actuals % Change Average production (boe/d) 10,600 10,900 9,588 12 Natural gas (mmcf/d) 38.5 39.0 35.4 9 Field condensate (bbls/d) 2,700 2,900 2,374 18 NGLs (bbls/d) 1,450 1,500 1,315 12 Percent liquids (%) 40 38 -- Adjusted funds flow (excluding $18.0 - $18.5 $13.3 40 hedges) ($ million) Adjusted funds flow (including hedges) ($ million) $14.5 - $15.0 $14.1 5 (1) Based on WTI crude oil price of $68 per barrel, NYMEX Henry Hub natural gas price of $2.95 per mmbtu and FX of 1.327 CAD per USD. (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 the working capital deficit excluding the current portion of the fair value of the financial instruments. September 2018 3

$ millions Boe/d BIGSTONE MONTNEY GROWTH 10,000 8,000 6,000 4,000 2,000 0 Montney Production Growth Liquids CAGR 63% Nat. Gas CAGR 50% 2012 2013 2014 2015 2016 2017 1H2018 Gas Liquids Non-Montney Montney asset growth funded largely through cash flow and non-core asset dispositions Life-to-date (LTD) capital includes land acquisitions and facility infrastructure build out 170 gross sections of land acquired Ownership in 100+ mmcf/d field gathering and plant processing capacity Focus on margin growth and ROCE Funding Bigstone Montney Source of Funding $500 $400 $463 million LTD Capital 10,000 8,000 Debt 7% Cumulative Proceeds $300 $200 $100 6,000 4,000 2,000 Equity 13% Cash Flow 52% $0 0 2013 2014 2015 2016 2017 Q1/18 Cum Capital Cum Proceeds Debt Production Dispositions 28% September 2018 4

Reserves (mboe) Reserves (mboe) CONSISTENT ECONOMIC RESERVE GROWTH Montney Development (2012 to 2018) Montney Reserves (mboe) 52 wells (41.1 net) drilled LTD 20,000 Proved Developed Producing Montney Other 2015/16 drilling focused on infill locations 15,000 2017 drilling focused on delineating west and south lands 3-Year Montney PDP FD&A to YE 2017 10,000 5,000 Montney CAGR 63% $14.40/boe 0 2012 2013 2014 2015 2016 2017 Montney Wells brought on Production 80,000 Total Proved Plus Probable 15 60,000 Montney Other 8 11 40,000 4 6 6 6 20,000 2012 2013 2014 2015 2016 2017 2018 0 2012 2013 2014 2015 2016 2017 September 2018 5

HOW DOES DELPHI S BIGSTONE MONTNEY RANK: Recognized as a top tier liquids-weighted asset DEE Among the highest IRR September 2018 Bigstone Montney economics driven by field condensate and NGL s 6

NETBACK COMPARISON SELECT MONTNEY PRODUCERS Condensate yields, total liquids content and operating netbacks are among the highest in the Montney Operating netbacks continue to increase as: Focus on liquids-rich West Bigstone Low margin, legacy production decreasing as a % of total (currently 10%) Netback (1) Second Quarter 2018 45.00 70% 40.00 35.00 30.00 25.00 60% 50% 40% 20.00 15.00 10.00 5.00 - DEE DEE Montney VII NVA KEL SRX CR BIR AAV Operating netback Royalties Operating Transportation % Liquids (Total) % Condensate 30% 20% 10% 0% (1) Excluding hedges Sources: DEE; Company MD&As September 2018 7

BUILT A DOMINANT LAND POSITION Largest Land Position at Bigstone Montney land base has grown to 170 gross sections (111 net) from 4 sections in 2011 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 Continue to identify and pursue additional consolidation opportunities * 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. September 2018 8

BIGSTONE INFRASTRUCTURE FULLY INTEGRATED Amine plant commissioned in Q2/18 and sending sweetened Montney gas to Bigstone 14-28 natural gas plant (25% Delphi working interest) West Bigstone 16-10 well producing to 100% Delphi 11-03 sweet gas plant September 2018 9

7-11 AMINE PLANT ON-STREAM Delphi 52 mmcf/d sour dehydration and compression facility Delphi 17 mmcf/d amine plant to sweeten Montney sour gas September 2018 10

BIGSTONE SWEET GAS PROCESSING PLANT Repsol / Delphi sweet natural gas processing plant Delphi 25% working interest 85 mmcf/d capacity significantly underutilized Now processing amine sweetened Montney gas Material operating cost savings September 2018 11

NEW AMINE PLANT IMPROVES CASH NETBACK Commissioned April 2018 Up to 17 mmcf/d (11 net) of raw gas Cash flow increases by about $0.60/mcf (1) on amine sweetened gas sold on AECO Cash flow impact increases to $0.80/mcf once Alliance lateral to Bigstone gas plant is reactivated Notes: (1) Assuming Delphi captures 75% of the difference between netback prices of Chicago via Alliance and AECO via NGTL through use of additional excess Alliance service to generate marketing income. September 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 Delphi captures value of excess service through assignment at a premium or marketing activity (1) 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/BC and sold in Chicago to generate marketing income. September 2018 13

GAS MARKETING IN 2H 2018 Approximately 60% of natural gas sold in Chicago generating significantly higher pricing than AECO. AECO exposure is hedged through marketing income earned on excess Alliance firm service. Reactivation of the Alliance lateral in 2019 will increase Chicago sales back to approximately 90% of total Natural Gas Sales by Market (1) 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 (2) ($mm/year) Change in cash flow ($mm/year) (1.4) 1.8 0.4 Chicago Gas Sales (1) Worsening AECO-Chicago basis increases Delphi marketing income and cash flow in 2018 (1) Based on estimated average daily gas sales in the last six months of 2018. (2) Based on an average of 24.4 mmcf/d of excess firm service on Alliance and assumes that Delphi captures 75% of arbitrage between Chicago and AECO. September 2018 14

CONTRACTED ALLIANCE SERVICE IS A VALUABLE ASSET Delphi s Alliance service worth approximately $32 million (1) The undiscounted value of the arbitrage between AECO and Chicago netback prices available through Delphi s Alliance service is approximately $32 million through 2021. 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) Based on strip pricing as of August 8, 2018 September 2018 15

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 $3.65/boe to netback Commodity Hedges Q3 2018 Q4 2018 2019 Natural gas (mcf/d) 21.0 17.4 10.2 Average hedge price (C$/mcf) $35 $30 $25 $20 $15 $10 $5 $0 -$5 -$10 -$15 Hedging Gains/Losses ($millions) Natural gas price spike in 2008 3.62 3.64 3.46 Crude oil (bbl/d) 2,100 2,100 1,798 Average hedge price (C$/bbl) 72.41 72.41 82.41 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 2017 Cold winter lifting natural gas prices in 2014 September 2018 16

OPERATIONS UPDATE September 2018 17

$/boepd Sand Lb/ft UNDERSTANDING RESULTS OF EVOLVING FRAC DESIGN Montney Frac Generation Design Evolution 1,800 1,600 1,400 Gen 6 Gen 5 West Bigstone Evolution to significantly more sand moving to West Bigstone 1,200 1,000 800 600 Gen 4 East Bigstone More at West - less at East Optimizing frac sizes to maximize capital efficiency 400 200 0 ` $20,000 $15,000 $10,000 $5,000 Gen 1 Gen 2 Gen 3 Montney Drill & Complete Capital Efficiency IP30 IP90 Mill / clean-out of a ball drop liner in a 2017 pad well brought production back in line with expectations Successful result of 65 stage hybrid frac at 16-10 West Bigstone (Gen 6) On-going testing of new ball drop technologies $0 September 2018 18

UNDERSTANDING PAD WELL OPERATIONS / RESULTS Offset Frac Well clean-out Initial production performance of 13-9 (and other pad wells) was below expectations Field Condensate up 66% Natural Gas up 50% A partial mill/clean-out of the ball drop liner has brought production back in-line with expectations 14 days 18 days September 2018 19

MONTNEY ECONOMIC MODEL Bigstone Montney Toe Up Two Section Horizontal Hypothetical Type Wells 30+ stage Slickwater Completion Economics/Metrics - Flat Pricing: WTI US$65/bbl, NYMEX US$2.80/mmbtu Type Rich Type Well Well Payout yrs 1.6 1.4 IRR % 53% 74% NPV 10 MM$ $4.5 $9.3 PI 1.6 2.3 F&D $/boe $7.31 $6.34 Target Capital D,C,E&TI MM$ $7.0 $8.0 Initial Sales Production (IP30 - first 30 day average) Gas mmcf/d 5.1 3.6 Field Condensate (2) bbl/mmcf 86 183 Total Liquids (C3+) (2,3) bbl/mmcf 129 227 Total Liquids (C3+) (2,3) bbl/d 662 822 Total IP30 boe/d 1,515 1,426 IP365 (first 365 day average) Gas mmcf/d 2.9 2.2 Field Condensate (2) bbl/mmcf sales 58 114 Total Liquids (C3+) (2,3) bbl/mmcf sales 101 158 Total Liquids (C3+) (2,3) bbl/d 294 348 Total IP365 boe/d 778 717 Reserves (sales) Gas bcf 3.7 4.0 Liquids (C3+) (2,3) mmbbl 0.3 0.6 Total mmboe 1.0 1.3 Note: See Montney Economic Model Assumptions in the Forward Looking Statement and Important Notes September 2018 20

IP180 CGR (bbl/mmcf sales) INCREASING CONDENSATE YIELDS Condensate Gas Ratios Significantly Greater in West Bigstone with Frac Design Changes 250 200 Delphi Bigstone Montney - IP180 CGR vs. IP30 CGR West Type Well - Stabilized CGR Type Well - Stabilized CGR 150 100 50 0 16-9 15-21 16-21 2-116-24 12-27 14-27 3-26 10-27 15-24 2-7 13-24 13-15 14-24 13-23 13-30 13-17 16-15 16-27 16-23 14-30 15-30 8-2115-2314-11 15-11 15-10 11-17 13-10 13-9 15-8 15-9 14-9 14-21 9-8 0 50 100 150 200 250 300 350 IP30 CGR (bbl/mmcf sales) 16-18 East wells 13-21 West wells Initial Production (IP) Rate Well Performance (1) Delphi Bigstone Montney 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 West Wells 1,062 238 872 177 684 151 563 135 Average East Wells 1,361 109 1,146 81 971 70 768 61 Average All Wells 1,271 148 1,063 110 897 91 730 75 (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. September 2018 21

Revenue ($/BOE) 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 45.00 40.00 35.00 30.00 25.00 20.00 15.00 10.00 5.00 - $21 $23 $32 $5 $5 $5 $9 $8 $7 $3 $3 $3 East All Wells West Royalties Opcosts Transportation Operating netback % Change West vs East Revenue 25% Royalty 25% Operating costs (15%) Transportation (2%) Netback 47% Field Condensate on a BOE basis Higher realized price Lower operating cost Lower transportation cost than natural gas (1) Based on US$ 65 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. September 2018 22

2H 2018 MONTNEY DRILLING PLANS 16-10 15-19 Offsetting successful delineation at West Bigstone 16-10 IP90: 613 bbls/d field condensate 1,226 boe/d 53% liquids 15-19 IP90: 605 bbls/d field condensate 1,300 boe/d 58% liquids Drilled or Drilling Near-Term Potential Locations 119 gross locations based on single Montney layer 5 to 6 wells per section September 2018 23

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. September 2018 24

FORWARD-LOOKING STATEMENTS AND IMPORTANT NOTES The following criteria reflects Montney economic modeling assumptions herein the presentation. 1. Flat pricing: NYMEX $2.80/mmbtu US, $3.59/mmbtu CDN; WTI $65.00/bbl USD; C5 $78.77/bbl CDN. 2. Type Well stabilized field condensate beyond month six is 45 bbl/mmcf sales; Rich Type Well stabilized field condensate production beyond month one is 103 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. 21 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. Six horizontal Montney wells at West Bigstone were time normalized, averaged and used to determine a proved plus probable reserve estimate. 6. Type well 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. September 2018 25

APPENDIX September 2018 26

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 1,161 121 849 108 685 106 495 100 14-21 3rd 2,788 40 1,606 180 1,258 145 968 128 702 115 16-21 3rd 2,858 40 1,968 134 1,541 102 1,258 103 907 85 15-8 4th 2,740 40 1,243 216 1,118 185 890 152 659 137 15-11 3rd 2,866 40 1,375 80 1,178 54 929 46 656 43 13-15 3rd 2,891 40 1,579 106 1,205 85 943 73 664 69 15-09 (3) 3rd 2,864 40 756 196 625 149 504 137 369 122 13-09 (3) 4th 2,813 40 895 185 668 164 543 151 13-17 (3) 3rd 2,876 40 562 112 575 69 486 62 14-09 (3) 4th 2,863 40 865 213 677 160 542 139 407 126 16-18 (3) 4th 2,881 40 500 182 605 87 519 69 13-10 4th 2,848 39 1,161 167 1,118 101 843 91 9-21 (3) 4th 2,841 40 899 140 715 109 16-12 4th 2,859 39 717 300 618 217 546 191 9-8 4th 2,574 38 941 202 833 141 661 123 13-7 4th 2,847 40 753 245 652 189 540 172 14-15 5th 2,879 49 1,130 139 1,054 99 887 82 15-19 5th 2,862 49 1,828 228 1,300 183 14-10 (3) 5th 2,856 47 902 132 790 99 16-07 5th 2,853 50 607 319 565 208 16-10 6th 2,855 65 1,434 310 1,226 177 16-11 4th 2,855 50 1,060 90 923 69 14-18 4th 2,875 50 1,306 156 1,083 103 16-19 5th 2,860 50 953 245 722 188 Average 3rd, 4th & 5th Gen Frac 2,829 42 1,138 173 953 126 788 105 644 90 (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. September 2018 27

2300, 333 7 th Avenue SW Calgary, Alberta T2P 2Z1 P (403) 265-6171 F (403) 265-6207 info@delphienergy.ca www.delphienergy.ca September 2018 28