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

January 2018 3

Grande Prairie

Bigstone

Montney

Edmonton

Calgary

4

6

8

6 6

17

0

2

4

6

8

10

12

14

16

18

2012 2013 2014 2015 2016 2017

CORPORATE INFORMATION

Ticker Symbol 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

Bigstone Montney Wells Drilled

(1) As at January 15, 2018.(2) Bank debt plus working capital deficiency as at September 30, 2017.

+ 2 wells of 2018 program started drilling

2017 OPERATIONAL HIGHLIGHTS

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)- $35.0 - $38.0

December 31, 2017 Net Bank Debt

($ million)- $37.0 - $42.0

Total Debt / Q4 FFO (annualized) - 2.2 – 2.4

4January 2018

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

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

(1) Estimate includes $6 million of 2018 program spent in 2017

GROWING THE DOMINANT LAND POSITION

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

Largest Land Position at Bigstone

January 2018 6

INFRASTRUCTURE LARGELY IN PLACE

Alliance/TCPL

Pembina

SemCams KA/K3

REPSOL Edson

Alliance/TCPL

Alliance/TCPL

Pembina

SemCams K3

To TCPL

Alliance/TCPL

Pembina

DEE Water Disposal

6,000 bpd capacity

DELINEATING THE LARGE LAND POSITION

January 2018 7

• 14 new wells on-stream in 2017

• 1 new well recently completed

• 2 new wells waiting on completion

7

WEST BIGSTONE EAST BIGSTONE

D3

D2

D1

B1

C

D1

C

D2

B1

Development & Delineation

100% South Montney Lands

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

13-10 and 15-19 results are outstanding

Industry de-risking offsetting lands

16-12 and 13-7 well results are positive

Multiple layers to drill

Natural gas is low H2S/sweet

Condensate yields increasing

West Bigstone

2017 delineation drilling program

has validated Delphi’s Bigstone Montney’s significant value potential

RECENT WELL RESULTS YIELD EVEN GREATER MARGINS

January 2018 8

Condensate Gas Ratios Improving with Frac Design Changes

Initial Production (IP) Rate Well Performance (1)

Frac Design Generation

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.

IP30 IP90 IP180 IP365

INCREASING NETBACKS

January 2018 9

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

% Change

16-12/13-7 versus Gen 1

Revenue 48%

Royalty 48%

Operating costs (24%)

Transportation (10%)

Netback 112%

(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.

Corporate netbacks increase with addition of higher condensate yield wells

Impact of Production Composition on Operating Netback for

Bigstone Montney(1)

NEW 5TH GENERATION FRAC DESIGN IMPROVING PERFORMANCE

January 2018 10

15-19-59-23W5 delineation well using 5th Generation Frac design tested

7.6 mmcf/d raw gas and 1,438 bbl/d field condensate.

10

100

1,000

10,000

0 30 60 90 120 150 180

Ga

s (

mcf/

d)

& F

ield

Co

nd

en

sa

te (

bb

l/d

)

Days on Production

Direct offset comparison of 5th to 3rd Generation Frac

13-15-60-23W5 Gas 13-15-60-23W5 Field Condensate

14-15-60-23W5 Gas 14-15-60-23W5 Field Condensate

Increased Condensate Rates and Yields

Shallower initial decline

3rd Gen

5th Gen

∆IP30: Gas and Plant NGL -373 boe/d

Field Condensate -76 boe/d

Total -449 boe/d … but higher production after IP30

IMPROVED PARENT / CHILD WELL MANAGEMENT

January 2018 11

10

100

1,000

10,000

Delphi 13-9-60-23W5 Montney

Field Condensate (bbl/d) Gas (mcf/d) CGR (bbl/mmcf)

• 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

expectations

Offset FracWell

Intervention

Field Condensate up 115%

Natural Gas up 54%

14 days 18 days

WESTERN-MOST WELLS: HIGHEST CONDENSATE YIELD TO DATE

January 2018 12

• Average IP30 field condensate yield of 272 bbl/mmcf sales

• Both wells completed with 40-stages and ~1,350 lb/ft of sand (4th Generation)

10

100

1,000

10,000Delphi 16-12-60-24W5 Montney

Field Condensate (bbl/d) Gas (mcf/d) CGR (bbl/mmcf)10

100

1,000

10,000Delphi 13-7-60-23W5 Montney

Field Condensate (bbl/d) Gas (mcf/d) CGR (bbl/mmcf)

Highest initial condensate yield

Shallower initial decline

• 6th 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

SECURE MARKET ACCESS FOR GROWTH

January 2018 13

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

Delphi/Alliance

Full Path Service to Chicago

(1) Delphi captures the value of excess Alliance firm service either by assigning it to 3rd parties at a premium above cost or by using it to transport

3rd party natural gas purchased in Alberta and sold in Chicago to generate marketing income.

Contracted Transportation

Service (mmcf/d)

GAS MARKETING IN 2018 – 100% SHELTERED FROM AECO CARNAGE

January 2018 14

(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.

• 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.

Increase in

spread between

AECO and

Chicago

Change in

AECO revenue

($ mm/year)

Change in

premiums

earned on

excess Alliance

service (3)

($mm/year)

Change in

cash flow

($mm/year)

US$0.20 /

mmbtu

(0.3) 0.5 0.2

Delphi Cash Flow Sensitivity to AECO-Chicago Basis

Worsening AECO-Chicago basis increases

Delphi cash flow in 2018

CONTRACTED ALLIANCE SERVICE IS A VALUABLE ASSET

January 2018 15

(1) Based on strip pricing as of January 12, 2018

• 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).

• 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.

Value of AECO-Chicago Arbitrage Available through

Delphi’s Alliance Transportation Service(1)Arbitrage between AECO and Chicago Available

through Delphi’s Alliance Transportation Service(1)

Delphi’s Alliance service worth > $40 million

Delphi expects to generate up to $7 million from excess Alliance service in 2018

ENTERING 2018 WITH OPERATIONAL MOMENTUM

16January 2018

2018 Planning Scenarios

13%

29%

37%

0%

10%

20%

30%

40%

-

5,000

10,000

15,000

50 55 60

(boe/d

)

WTI (US$/bbl)

2018 Annual Production

Production Growth (YoY %)

124%105%

121%

0%

50%

100%

150%

200%

0

20

40

60

80

100

50 55 60

($ m

m's

)

WTI (US$/bbl)

2018 CAPEX and Cash Flow

CAPEX CF CAPEX (% of CF)

Expect 2018 budget to be released in mid-February

Production data from 2017 delineation drilling important

input for 2018 planning and forecasting

Current planning scenarios for 2018 contemplate a

modest outspend of cash flow in 2018

Hedge book and Chicago/Alliance gas marketing

continues to mitigate commodity price volatility

Early start to 2018 drilling program in Dec/17

5 new wells expected on production in 1H/18

2 – 5 DUC’s potentially ready for completion into Q3/18

Phase 1 Amine plant scheduled for Q2/18 start-up

Excess Alliance-Chicago transportation firm service

provides arbitrage to AECO/Station 2 price weakness

generating additional revenue

2018 AND BEYOND – MAINTAINING KEY VALUES

January 2018 17

Delineation drilling in 2017 has validated Delphi’s Bigstone Montney’s significant value potential

Superior condensate rich well performance yielding top decile capital efficiencies

World Class Montney Asset

Infrastructure and Operational Control

Land Inventory

Market Access and Hedging Strategy

Operational Performance

Growth utilizing existing major infrastructure, with minimal capital requirements

Operatorship with ownership in strategic infrastructure with strong industry partner relationship

Continued new well innovations resulting in increasing condensate yields and operating margin growth

Operating efficiency gains coming in 2018 with increased pad drilling

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

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

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 relateto future events or the Company’s future performance and are based upon the Company’s internal assumptions and expectations. All statements other than statements ofpresent 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 withoutlimitation, this presentation contains forward-looking statements and information relating to petroleum and natural gas production estimates and weighting, projected crudeoil and natural gas prices, future exchange rates, expectations as to royalty rates, expectations as to transportation and operating costs, expectations as to general andadministrative costs and interest expense, expectations as to capital expenditures and net debt, planned capital spending, future liquidity and Delphi’s ability to fund ongoingcapital requirements through operating cash flows and its credit facilities, supply and demand fundamentals for oil and gas commodities, timing and success of developmentand exploitation activities, cash availability for the financing of capital expenditures, access to third-party infrastructure, treatment under governmental regulatory regimesand tax laws and future environmental regulations. Furthermore, statements relating to “reserves” are deemed to be forward-looking statements as they involve the impliedassessment, based on certain estimates and assumptions that the reserves described can be profitable in the future. The forward-looking statements and informationcontained in this presentation are based on certain key expectations and assumptions made by Delphi. The following are certain material assumptions on which theforward-looking statements and information contained in this presentation are based: the stability of the global and national economic environment, the stability of andcommercial acceptability of tax, royalty and regulatory regimes applicable to Delphi, exploitation and development activities being consistent with management’sexpectations, production levels of Delphi being consistent with management’s expectations, the absence of significant project delays, the stability of oil and gas prices, theabsence of significant fluctuations in foreign exchange rates and interest rates, the stability of costs of oil and gas development and production in Western Canada, includingoperating costs, the timing and size of development plans and capital expenditures, availability of third party infrastructure for transportation, processing or marketing of oiland 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 consistentwith management’s expectations, weather affecting Delphi’s ability to develop and produce as expected, contracted parties providing goods and services on the agreedtimeframes, 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 tocurrent and new customers. Additionally, estimates as to expected average annual production rates assume that no unexpected outages occur in the infrastructure that theCompany 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 meettiming and production expectations. Commodity prices used in the determination of forecast revenues are based upon general economic conditions, commodity supply anddemand forecasts and publicly available price forecasts. The Company continually monitors its forecast assumptions to ensure the stakeholders are informed of materialvariances from previously communicated expectations. Financial outlook information contained in this presentation about prospective results of operations, financial positionor cash flows is based on assumptions about future events, including economic conditions and proposed courses of action, based on management’s assessment of therelevant information currently available. Readers are cautioned that such financial outlook information contained in this presentation should not be used for purposes otherthan for which it is disclosed. Although the Company believes that the expectations reflected in such forward-looking statements and information are reasonable, it can giveno assurance that such expectations will prove to be correct and such forward-looking statements should not be unduly relied upon. Since forward-looking statements andinformation 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 giventhat 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 ormore of these risks or uncertainties materialize, or should assumptions underlying forward-looking statements prove incorrect, actual results may vary materially from thosecurrently 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 asoperational risks in development, exploration and production, delays or changes in plans with respect to exploration or development projects or capital expenditures, theuncertainty 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 governmentalregulation of the oil and gas industry and changes in tax, royalty and environmental legislation. Additional information on these and other factors that could affect theCompany’s operations or financial results are included in the Company’s most recent Annual Information Form and other reports on file with the applicable securitiesregulatory 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 theCompany’s expectations for the coming year. The forward-looking statements and information may not be appropriate for other purposes. Delphi undertakes no obligationto update publicly or revise any forward-looking statements or information, whether as a result of new information, future events or otherwise, unless so required byapplicable 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 NOTESThe 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

January 2018 21

Initial Production (IP) Rate Well Performance (1)

Well(2) Frac Design Horizontal Number

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.

IP30 IP90 IP180 IP365

MONTNEY ECONOMIC MODEL

January 2018 22

Rich Type Well13-21 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

DEE Type Well

Economics/Metrics - January 12, 2018 Strip Pricing(1)

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

Bigstone Montney Toe Up Two Section Horizontal Hypothetical Type Wells

30+ stage Slickwater Completion

PROVEN RISK MANAGEMENT PROGRAM

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

January 2018 23

Consistent Hedge Performance

-$15

-$10

-$5

$0

$5

$10

$15

$20

$25

$30

$35

2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017E

Hedging Gains/Losses ($millions)

Cold winter lifting natural

gas prices in 2014

Natural gas

price spike in

2008Steady decline of natural

gas prices from 2009 to

2013

Collapse of natural gas and

crude oil prices

Commodity HedgesQ1 2018 Q2 2018 Q3 2018 Q4 2018 2019

Natural gas (mcf/d) 20.0 21.0 21.0 17.4 7.2Average 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 600Average hedge price (C$/bbl) 70.50 71.20 72.41 72.41 70.13

2300, 333 – 7th Avenue SW

Calgary, Alberta T2P 2Z1

P (403) 265-6171

F (403) 265-6207

info@delphienergy.ca

www.delphienergy.ca

January 2018 24