May 22, 2018

AGM PRESENTATION

BIGSTONE – PROLIFIC, LIQUIDS RICH MONTNEY

May 2018 2

Grande Prairie

Bigstone

Montney

Edmonton

Calgary

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

Pure play MONTNEY E&P company with WORLD

CLASS ASSETS:

MANAGING THROUGH COMMODITY PRICE CYCLES

May 2018 3

$(5.00)

$-

$5.00

$10.00

$15.00

$20.00

$25.00

Q1

/12

Q3

/12

Q1

/13

Q3

/13

Q1

/14

Q3

/14

Q1

/15

Q3

/15

Q1

/16

Q3

/16

Q1

/17

Q3

/17

Q1

/18

Netback w/o Hedge Hedge Gain

Focus on Montney

Margin Growth

Prolonged price weakness

protected by hedges

Early Stage Montney

Production GrowthReturn to Montney

Production Growth

Ne

tba

ck (

$/b

oe

)

BIGSTONE MONTNEY GROWTH IN 2017

4May 2018

Production Q4 2016 to Q4 2017

Total corporate increased 35 percent to

9,588 boe/d driven by Montney development

Field condensate increased 77 percent to

2,374 bbls/d

Total Proved increased 40 percent to

26.9 mmboe

Total Proved Plus Probable increased

33 percent to 48.5 mmboe

Total Proved Montney field condensate

increased 76 percent to 5.5 mmboe

Total Proved Plus Probable Montney field

condensate increased 68 percent to

9.7 mmboe

Reserves YE 2016 to YE 2017

2017 & Q1 2018

Montney drills

BIGSTONE MONTNEY GROWTH

May 2018 5

Montney Production Growth

0

2,000

4,000

6,000

8,000

10,000

2012 2013 2014 2015 2016 2017 1H2018

Boe/d

Gas Liquids Non-Montney

Liquids CAGR 63%

Nat. Gas CAGR 50%

Funding Bigstone Montney Source of Funding

Cash Flow52%

Dispositions28%

Equity13%

Debt7% Cumulative

Proceeds

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

$463 million

LTD Capital

0

2,000

4,000

6,000

8,000

10,000

$0

$100

$200

$300

$400

$500

2013 2014 2015 2016 2017 Q1/18

Cum Capital Cum Proceeds Debt Production

$ m

illio

ns

CONSISTENT ECONOMIC RESERVE GROWTH

December 2017 6

Montney Reserves (mboe)

52 wells (41.1 net) drilled LTD

2015/16 drilling focused on infill locations

2017 drilling focused on delineating west and south

lands

3-Year Montney PDP FD&A to YE 2017

$14.40/boe

Montney Development (2012 to 1H 2018)

0

5,000

10,000

15,000

20,000

2012 2013 2014 2015 2016 2017

Reserv

es (

mboe)

Proved Developed Producing

Montney Other

Montney CAGR 63%

0

20,000

40,000

60,000

80,000

2012 2013 2014 2015 2016 2017

Re

se

rve

s (

mb

oe

)

Total Proved Plus Probable

Montney Other

4

6

8

6 6

15

7

2012 2013 2014 2015 2016 2017 1H2018

Montney Wells brought on Production

HOW DOES DELPHI’S BIGSTONE MONTNEY RANK:

7May 2018

DEE

DEE

Bigstone Montney economics driven by field condensate and NGL’s

Recognized as a top tier liquids-weighted asset

Among the highest IRRAmong the lowest break-even gas price

NETBACK COMPARISON – MONTNEY PRODUCERS

May 2018 8

Condensate yields, total liquids content and operating netbacks are among the highest

Operating netbacks continue to increase as:

• Focus on liquids-rich West Bigstone

• Amine sweetening facility reduces operating costs (third-party processing)

• Legacy production (10% of production; 2% of operating income) decreasing as a % of total

Sources: DEE; Company MD&As

0%

10%

20%

30%

40%

50%

60%

70%

-

5.00

10.00

15.00

20.00

25.00

30.00

35.00

40.00

45.00

DEE DEE Montney VII NVA KEL SRX CR BIR AAV

Netback(1) First Quarter 2018

Operating netback Royalties Operating Transportation % Liquids (Total) % Condensate

(1) Excluding hedges

BUILT A DOMINANT LAND POSITION

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.

May 2018 9

Largest Land Position at Bigstone

May 2018 10

BIGSTONE INFRASTRUCTURE FULLY INTEGRATED

Amine plant

commissioned and

sending sweetened

Montney gas to Bigstone

14-28 natural gas

processing plant (25%

Delphi working interest)

West Bigstone 16-10

well producing to 100%

Delphi 11-03 sweet gas

plant

7-11 AMINE PLANT ON-STREAM

May 2018 11

Delphi

52 mmcf/d sour

dehydration and

compression

facility

Delphi

17 mmcf/d amine

plant to sweeten

Montney sour gas

BIGSTONE SWEET GAS PROCESSING PLANT

May 2018 12

Repsol / Delphi sweet natural gas processing plant

Delphi 25% working interest

85 mmcf/d capacity

significantly underutilized

Amine sweetened Montney gas now being processed here

Material operating cost savings

May 2018 13

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.

SECURE MARKET ACCESS FOR GROWTH

May 2018 14

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

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/BC and sold in Chicago to generate marketing income.

Contracted Transportation

Service (mmcf/d)

GAS MARKETING IN 2018 – 100% SHELTERED FROM AECO CARNAGE

May 2018 15

(1) Based on estimated average daily gas sales in the last nine months of 2018.

(2) Based on an average of 18 mmcf/d of excess firm service on Alliance and assumes that Delphi captures 75% of arbitrage between Chicago

and AECO.

• Approximately 80% of natural gas sold in Chicago generating

significantly higher netback pricing than AECO.

• AECO exposure is hedged through marketing income earned on

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 (2)

($mm/year)

Change in

cash flow

($mm/year)

US$0.20 /

mmbtu

(1.0) 1.3 0.3

Delphi Cash Flow Sensitivity to AECO-Chicago Basis

Worsening AECO-Chicago basis increases

Delphi cash flow in 2018

Natural Gas Sales by Market in 2018 (1)

Chicago Gas Sales in 2018 (1)

CONTRACTED ALLIANCE SERVICE IS A VALUABLE ASSET

May 2018 16

(1) Based on strip pricing as of May 17, 2018

• The undiscounted value of the arbitrage between AECO and Chicago netback prices available

through Delphi’s Alliance service is approximately $25 million through 2021.

Value of AECO-Chicago Arbitrage Available through

Delphi’s Alliance Transportation Service

Arbitrage between AECO and Chicago Available

through Delphi’s Alliance Transportation Service(1)

Delphi’s Alliance service worth approximately $25 million (1)

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

May 2018 17

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 2017

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 Hedges 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) 3.88 3.86 3.86 3.87 3.90

Crude oil (bbl/d)2,256 2,500 2,100 2,100 798

Average hedge price

(C$/bbl) 70.50 71.20 72.41 72.41 71.71

OPERATIONS UPDATE

May 2018 18

AN ACTIVE 2017 AND Q1/2018

May 2018 19

$117MM 2017 capital

17 (11.0 net) wells drilled 6 (3.9 net) delineation wells

7 (4.5 net) pad wells

Start of 7-11 Amine project

Expansion of 7-11 and 5-8

comp/dehy facilities

21 km of main gathering

infrastructure

Expansion of water disposal

facility

Added 14.5 (13.5 net)

sections Montney rights

$41MM 2018 Q1 capital

4 (2.6 net) wells drilled 1 (0.65 net) delineation well

6 (3.9 net) wells completed

Commissioned Amine plant in April

7 (4.5 net) wells on stream YTD

WEST BIGSTONE EAST BIGSTONE

D3

D2

D1

B1

C

D1

C

D2

B1

CVE

ATH

XTO

Dienarian

0

200

400

600

800

1,000

1,200

1,400

1,600

1,800

San

d L

b/f

t

`

Gen 1

Gen

2

Gen 3

Gen 4

Gen 5

Gen 6

West Bigstone

20May 2018

Montney Frac Generation Design Evolution

UNDERSTANDING RESULTS OF EVOLVING FRAC DESIGN

East Bigstone

$0

$5,000

$10,000

$15,000

$20,000

$/b

oe

pd

Montney Drill & Complete Capital Efficiency

IP30 IP90

Evolution to significantly more

sand moving to West Bigstone

More at West - less at East

Optimizing frac sizes to

maximize capital efficiency

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

21

10

100

1,000

10,000

0 30 60 90 120 150 180

Ga

s (

mc

f/d

) &

Fie

ld C

on

den

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

Early time results

Increased condensate rates and yields

Lower initial gas rates with shallower

decline

3rd Gen

5th Gen

∆IP30: Gas and Plant NGL -373 boe/d

Field Condensate -76 boe/d

Total -449 boe/d

UNDERSTANDING RESULTS OF EVOLVING FRAC DESIGN

May 2018

10

100

1,000

10,000

0 30 60 90 120 150 180

Ga

s (

mc

f/d

) &

Fie

ld C

on

den

sa

te (

bb

l/d

)

Days on Production

5th Gen Frac (14-15-60-23W5) vs 3rd Gen Frac (13-15-60-23W5)

13-15-60-23W5 Gas 13-15-60-23W5 Field Condensate14-15-60-23W5 Gas 14-15-60-23W5 Field Condensate

3rd Gen

5th Gen

Production from 5th Gen frac has started to track 3rd Gen. Based on this

result, we scaled back to Gen 3 on subsequent wells at 14-18 and 16-11.

UNDERSTANDING RESULTS OF EVOLVING FRAC DESIGN

May 2018

May 2018 23

Initial production

performance of 13-9

(and other pad wells)

was below expectations

A partial mill/clean-out

of the ball drop liner has

brought production

back in-line with

expectations

Offset FracWell

clean-out

Field Condensate up 66%

Natural Gas up 50%

14 days 18 days

UNDERSTANDING PAD WELL OPERATIONS / RESULTS

WESTERN-MOST WELLS: HIGHEST CONDENSATE YIELD TO DATE

May 2018 24

• Average IP90 field condensate yield of 203 bbl/mmcf sales

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

Highest initial condensate yield

Shallower initial decline

MONTNEY ECONOMIC MODEL

May 2018 25

Note: See Montney Economic Model Assumptions in the Forward Looking Statement and Important Notes

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

Bigstone Montney Toe Up Two Section Horizontal Hypothetical Type Wells

30+ stage Slickwater Completion

INCREASING CONDENSATE YIELDS

May 2018 26

Condensate Gas Ratios Significantly Greater in West Bigstone with Frac Design Changes

15-10

10-27

16-23

15-24

15-3011-17

15-21

13-30

2-1

2-78-2116-15

3-26

13-2316-27

12-2716-24

13-24

14-30

14-2414-27

13-21

15-2314-11

16-9

14-21

16-21

15-8

15-11

13-15

15-9

13-9

13-17

14-9

16-18

13-10

9-8

0

50

100

150

200

250

0 50 100 150 200 250 300 350

IP1

80

CG

R (

bb

l/m

mcf

sale

s)

IP30 CGR (bbl/mmcf sales)

Delphi Bigstone Montney - IP180 CGR vs. IP30 CGR

West Type Well - Stabilized CGRType Well - Stabilized CGR

West wells

East wells

Initial Production (IP) Rate Well Performance (1)

Delphi Bigstone Montney

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 1,031 232 836 172 724 142 690 144

Average East Wells 1,361 109 1,156 81 974 69 768 61

Average All Wells 1,267 144 1,078 103 919 85 762 68

(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.

IP30 IP90 IP180 IP365

INCREASING NETBACKS

May 2018 27

Field Condensate on a BOE basis↑ Higher realized price

↓ Lower operating cost

↓ Lower transportation cost than

natural gas

% Change

West vs East

Revenue 25%

Royalty 25%

Operating costs (15%)

Transportation (2%)

Netback 47%

(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.

Corporate netbacks increase with addition of higher condensate yield wells

Impact of Production Composition on IP90 Operating

Netback for Bigstone Montney(1)

$3 $3 $3

$9 $8 $7

$5 $5 $5

$21 $23

$32

-

5.00

10.00

15.00

20.00

25.00

30.00

35.00

40.00

45.00

50.00

East All Wells West

Reve

nu

e ($

/BO

E)

Royalties Opcosts Transportation Operating netback

2H 2018 MONTNEY DRILLING PLANS

May 2018 28

Offsetting successful delineation

at West Bigstone

15-19 IP30:

950 bbls/d field condensate highest yet for Delphi

1,828 boe/d 62% liquids

16-10 was recently brought on

production through the 100%

DEE Negus gas plant

Over the first 7 full days on

prod:

1,437 bbls/d field

condensate

1,934 boe/d 80% liquids

119 gross locationsbased on single Montney layer

5 to 6 wells per section

15-19

16-10

2018 GUIDANCE FOR FIRST HALF 2018

29May 2018

2018 capital program supported by

significant production and cash flow growth

through 2017

Condensate growth of 27% in Q1/18 over

Q1/17

Cash netbacks in Q1/18 23% greater than

Q1/17

Delineation drilling success sets up multiple

options for “ultra-rich” condensate locations

in 2018 and beyond

Production data from new wells important

input for 2H/18 planning

First Half 2018 capital program

7 new wells on production in 1H/18

1H/18 forecast takes into account production

downtime for new well completions and amine

plant construction/commissioning

Phase 1 Amine plant on-stream

Second Half 2018 capital program expected

in late Q2/18

Strong return on capital, increased cash flow

largely driven by continued condensate

production growth

2018 First

Half GuidanceQ1

Actuals

Q2

ForecastNet Capital Program ($ million) $38 - $45 $41.2 $5.5 - $6.0

Gross Well Count Drilled (net) 4 (2.6) 4 (2.6) -

Gross Well Count On Production (net) 5 (3.3) – 7 (4.6) 4 (2.6) 3 (2.0)

2018 First Half

Guidance(1) Q1 Actuals Q2 Forecast(2)

Average Production (boe/d) 9,800 – 10,200 9,515 10,600 – 11,000

Natural Gas (mmcf/d) 35.0 – 37.0 33.7 37.0 – 39.0

Field Condensate (bbls/d) 2,450 – 2,550 2,472 2,800 – 2,900

NGLs (bbls/d) 1,470 – 1,530 1,418 1,550 – 1,650

Percent Liquids (%) 40 41 41

Adjusted Funds Flow (“AFF”)

($ million)$25.0 - $27.0 $11.4 $14.5 - $15.5

Operating Netback ($/boe,

before hedging)$21.50 $21.42 $21.70

Cash Netback ($/boe) $14.25 $13.35 $15.10

Net Debt (3) ($ million) $149 –$154 $166.4 $156 –$158

Net Debt / AFF (annualized) 2.9 – 3.0 3.6 2.5 – 2.7

(1) Based on WTI crude oil price of $62 per barrel, NYMEX Henry Hub natural gas price of $2.80 per

mmbtu and FX of 1.27 CAD per USD.

(2) Based on WTI crude oil price of $65 per barrel, NYMEX Henry Hub natural gas price of $2.80 per

mmbtu and FX of 1.27 CAD per USD.

(3) 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.

May 2018 30

CASH FLOW FUNDED GROWTH

Capital program of $46 million per year is required to maintain production

Drill, complete, equip and tie-in 7 (4.6 net) wells(1)

Annualized Q1 cash flow before hedges was $56 million (WTI price of $62.89)

Annualized Q2 forecast cash flow before hedges is $67 million

Significant internally-funded growth potential

Declining WTI hedge position throughout 2018 into 2019

Notes:

(1) Based on West Bigstone type curve.

(2) Based on NYMEX HH natural gas price of $2.80 per mmbtu and FX of 1.27 CAD per USD..

Hedged

(million)

Unhedged

(million)

$65 WTI $60 $67

$70 WTI $64 $77

$75 WTI $67 $86

$80 WTI $71 $95

Annualized Q2 Cash Flow Sensitivity to the Price of WTI Crude Oil(2)

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.

May 2018 31

FORWARD-LOOKING STATEMENTS

AND IMPORTANT NOTESThe 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 ref lect 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.

May 2018 32

APPENDIX

May 2018 33

INDIVIDUAL MONTNEY WELL DATA

May 2018 34

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 1,161 121 849 108 685 106 495 100

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

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

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

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

9-8 4th 2,574 38 941 202 833 141 661 123

13-7 4th 2,847 40 753 245 652 189

14-15 5th 2,879 49 1,130 139 1,054 99

15-19 5th 2,862 49 1,828 228

14-10(3) 5th 2,856 47 902 132

16-07 5th 2,853 50 607 319

16-10 6th 2,855 65 waiting on IP30

16-11 4th 2,855 50 1,060 90

14-18 4th 2,875 50 1,306 156

16-19 5th 2,860 50 953 245

Average 3rd, 4th & 5th Gen Frac 2,821 40 1128 169 955 119 809 98 689 79

(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

46

86 6

15

7

New Montney Wells Producing

2300, 333 – 7th Avenue SW

Calgary, Alberta T2P 2Z1

P (403) 265-6171

F (403) 265-6207

info@delphienergy.ca

www.delphienergy.ca

May 2018 35