OCTOBER 2019

OCTOBER PRESENTATION

CORPORATE OVERVIEW

October 2019 2

CORPORATE INFORMATION

Ticker Symbol TSX:DEE

Basic Shares Outstanding (mm) 185.5

Enterprise Value (mm) $180.0

Bank Debt (1) / Credit Facility (mm) $64.0/ $90.0

5 Year Senior Secured Notes (mm)

Maturity Date: July 2021

$105.0

(1) Estimate of bank debt as of September 30, 2019 includes working capital and excludes $7.4 million of outstanding Letters of Credit

$40

$60

$80

$100

$120

Q3/18A Q4/18A Q1/19A Q2/19A Q3/19E Q4/19E

Debt & WC LC's

Ne

t B

ank

Deb

t (

$ m

m)

(in

c/ w

ork

ing

cap

ital

)

SENIOR CREDIT FACILITY

Bank(s) reducing lending values

42% Reduction in Bank Debt Capex << Cash Flow Sale of XS Alliance Service Increased Liquidity

Q2 / 2019 OPERATIONAL HIGHLIGHTS

Corporate Production (boe/d) 9,157

Condensate & Pentanes / NGL’s (bbl/d) 3,063 33%

Natural Gas Liquids (bbl/d) 944 11%

Natural Gas (mmcf/d) 30.9 56%

Operating Netback ($/boe) $20.79

Grande Prairie

Bigstone

Montney

Edmonton

Calgary

DELPHI: A PURE PLAY MONTNEY E&P COMPANY

October 2019 3

Bigstone is a liquids-rich Montney asset

yielding top operating margins

Increasing condensate production

and high stable yields

Owned infrastructure leading to

lower operating costs

Pad drilling driving capex efficiencies

Largest operated land position

Large drilling inventory

Alliance / Chicago natural gas

market access

Proven commodities hedging

strategy

Finding relevancy in today’s capital markets

A DOMINANT OPERATED LAND POSITION

Montney land base has grown to 148

gross sections (97 net)

Significant land position allows for

efficient operations, control over

infrastructure and scalable

development

19+ year drilling inventory* on

approximately 118 gross undeveloped

(including partially undeveloped)

sections:

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 118 sections, increasing in well density from NE to SW.

Refer to disclaimer for further details.

October 2019 4

Largest Land Position at Bigstone

WEST BIGSTONE: MULTIPLE LAYERS COULD DOUBLE INVENTORY

October 2019 5

DEE 6 wells on Section 10:

Targeting Upper D1, D2, D3

275 m well spacing

15-20 m vertical separation

Competitor 2 wells drilled:

Targeting C, D1, Lower D2

Pad built for up to 16 wells

200 m well spacing

Competitor

Multi-Well Pad

Waiting on

CompletionCompetitor

License

Section 10

4 Well Pad

On Production

DEE

XTO

INCREASING CONDENSATE YIELDS

6

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 FCondy Field CGR Total FCondy Field CGR Total FCondy Field CGR Total FCondy Field CGR

(boe/d) (bbl/d) (bbl/mmcf) (boe/d) (bbl/d) (bbl/mmcf) (boe/d) (bbl/d) (bbl/mmcf) (boe/d) (bbl/d) (bbl/mmcf)

Average West Wells 1,055 588 277 855 415 207 699 311 171 528 213 143

Average East Wells 1,340 440 108 1,127 308 80 927 230 70 699 158 62

Average All Wells 1,227 498 175 1,019 350 131 848 258 105 649 174 86

(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

October 2019

NETBACK COMPARISON – SELECT MONTNEY PRODUCERS

October 2019 7

Sources: DEE; Company MD&As(1) Excluding hedges. DEE hedge gain $2.50 per boe.

Delphi’s condensate yields, total liquids content and operating netbacks

are among the highest in the Montney

0%

10%

20%

30%

40%

50%

60%

$0.00

$10.00

$20.00

$30.00

$40.00

$50.00

$60.00

DEE VII NVA KEL SRX CR BIR AAV

Operating Netback Q2 2019

Operating netback Royalties Operating

Transportation % Liquids (Total) % Condensate

Lean Montney Producers

Liquids-Rich Producers75% greater netback

DEE Water

Disposal

(16-34-59-21W5)

October 2019 8

BIGSTONE INFRASTRUCTURE FULLY INTEGRATED

Invested $100 mm in facility and

pipeline infrastructure over the

past 7 years

Montney gas processed at 4

different plants Pipeline connecting 1-03 to

Amine allowing movement from

West to East for improved

pricing

Amine plant sending sweetened

Montney gas to Bigstone 14-28

natural gas plant (25% Delphi

working interest)

West Bigstone 16-10 and 15-10

wells producing to 100% Delphi

11-03 sweet gas plant

3 of 4 plants dually connected to

Alliance and TCPL

Maintaining flexibility to preferred

natural gas markets

REPSOL

Sour Gas Facility

10 mmcf/d

DEE 7-11

Sour Montney Facility

52 mmcf/d

4,400 bbl/d condensate

DEE Amine Plant

17 mmcf/d

DEE 11-03

Sweet Gas Plant

15 mmcf/d

DEE 5-08

Sour Montney Facility

10 mmcf/d

DEE 1-03

Sour Montney Facility

7 mmcf/d

3,000 bbl/d condensate

Alliance/TCPL/Pembina

SemCams KA/K3

Alliance (2022)

TCPL

Alliance/TCPL/Pembina

SemCams K3Allia

nce/T

CP

L

RE

PS

OL E

dson

TC

PL

CATAPULT

Water Disposal Facility

P/L connected to DEE

REPSOL 14-28

Sweet Gas Plant

85 mmcf/d

Existing DEE Pipeline/Plant

Infrastructure

7-11 AMINE PLANT DELIVERING GAS TO BIGSTONE PLANT

October 2019 9

Delphi

52 mmcf/d sour

compression and

dehydration

facility

Delphi

17 mmcf/d amine

plant sweetens

Montney sour gas

Delivers gas to

Bigstone Plant for

final processing at

much lower cost

than K3 and Edson

BIGSTONE SWEET GAS PROCESSING PLANT

October 2019 10

Repsol / Delphi sweet natural gas processing plant

Delphi 25% working interest - 85 mmcf/d capacity

Significantly under-utilized

Excess capacity to support second amine plant

Now processing amine sweetened Montney gas

Material operating cost savings

30

7

22

Alliance Firm Alliance IT TCPL Firm

SECURE MARKET ACCESS FOR GROWTH

11

Alliance

37 mmcf/d of firm and priority interruptible service

Access to premium pricing via Chicago City Gate

Full utilization of service in 2022 with reactivation of Bigstone Plant Alliance Lateral Delphi captures value of excess service through assignment at a premium or marketing activity

TCPL

22 mmcf/d firm service

Low cost service for growth beyond 2019

Delphi/Alliance

Full Path Service to Chicago

1. Subsequent to sale of 16 mmcf/d of excess Alliance service in September 2019.

Contracted Transportation

Service (mmcf/d)1

October 2019

GAS MARKETING

October 2019 12

(1) Based on Q2/19 average daily gas sales of 30 mmcf/d (45% AECO).

.

Approximately 55% of natural gas sold in Chicago generating significantly higher pricing than AECO

Reactivation of the Alliance pipeline lateral at Bigstone plant in 2022 will increase Alliance - Chicago sales

to approximately 90% of total

AECO 10%

Chicago 90%

Natural Gas Sales by Market - 2022

AECO 45%

Chicago 55%

Natural Gas Sales by Market (1)

PROVEN RISK MANAGEMENT PROGRAM

Majority of near term production is hedged

Risk management contracts generally put in

place over a 12 - 36 month period

Over 13 years 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

October 2019 13

Consistent Hedge Performance

-$20

-$10

$0

$10

$20

$30

$40

2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019*

Hedging Gains/Losses ($millions)

Cold winter lifting natural

gas prices in 2014

Natural gas

price spike in

2008

Steady decline of natural

gas prices from 2009 to

2013

Collapse of natural gas and

crude oil prices

Commodity Hedges Q4 2019 1H 2020 2H 2020

Natural gas (mmcf/d) 11.7 8.8 2.5

Average hedge price (C$/mcf)(2) $3.43 $3.37 $3.29

% of natural gas production

hedged(3)

38% 28% 8%

Crude oil (bbl/d) 2,350 2,000 1,500

Average hedge price (C$/bbl) $87.89 $83.31 $83.12

Propane (bbl/d) 400 100 100

Average hedge price (C$/bbl) $44.16 $42.69 $42.69

% of condensate & NGL production

hedged(3)

69% 52% 40%

(1) Assumes an FX of 1.32 CAD per USD.

(2) Includes the impact of NYMEX HH natural gas – Chicago basis hedges.

(3) Based on Q2 production of 30.9 mmcf/d of natural gas production, 4,007 bbl/d of condensate and NGL

production

* Mark-to-market value of 2019 hedges as at September 30, 2019

BIGSTONE MONTNEY

OPERATIONAL OVERVIEW

14October 2019

WEST BIGSTONE: DELINEATION SHIFTS TO DEVELOPMENT

15

Ultra-rich West Bigstone:

12 wells now on production

4 well pad on in April 2019

15-10 and 16-10 offsets

are best wells drilled LTD

by Delphi

Section 19 and 31 wells

are also ultra-rich

condensate wellsSections 19 and 31

5 Wells

On ProductionCompetitor

Multi-Well Pad

Waiting on

CompletionCompetitor

License

Section 10

4 Well Pad

On Production

15-10 and 16-10

On Production

October 2019

MOST RECENT WEST BIGSTONE RESULTS

16

13-34-60-24W5 four-well pad

Observing performance over the first 120 -180 days will be necessary to determine impacts of the increased

fracture intensity

Increased stage counts to 80 (50 ball drop and 30 Perf & Plug) on two eastern-most wells directly offsetting 15-10

Cased hole extreme limited entry with 40 stage x 5 clusters = 200 perf clusters on two western-most wells

Larger pads will reduce completion costs

Pad drilling will greatly reduce frac hits (offset frac hits impact gas rate more than field condensate rate)

Initial Production (IP) Rate Well Performance (1)

Well/Pad(2) Frac Design Horizontal Number

Generation Length of Fracs Total  Sales Field Condy Liquids Total  Sales Field Condy Liquids Total  Sales Field Condy Liquids

to Gas Yield (%) to Gas Yield (%) to Gas Yield (%)

(metres) (boe/d) (bbl/mmcf) (boe/d) (bbl/mmcf) (boe/d) (bbl/mmcf)

15-19 5th 2,862 49 1,828 228 62% 1,300 183 58% 974 168 56%

16-07 5th 2,853 28 607 319 69% 565 208 60% 457 183 58%

16-10 6th 2,855 64 1,441 317 67% 1,234 181 54% 1,035 150 50%

16-19 5th 2,860 34 953 245 63% 722 188 58% 569 167 56%

02/16-31 3rd 2,944 49 1,095 340 70% 800 304 67% 613 279 66%

02/15-19 3rd 2,687 50 998 245 63% 754 199 59% 586 180 57%

15-10 6th 2,963 64 1,294 245 61% 1,100 153 51% 781 158 52%

02/15-10 7th 2,869 80 980 233 62% 852 170 56%

03/16-31 6th 2,938 64 1,173 394 72% 902 312 68% 714 272 65%

14-10 7th 2,945 79 1,171 330 69% 945 238 63%

12-10 8th 2,636 41(3) 756 558 78% 585 408 73%

13-10 8th 2,951 40(3) 886 381 72% 670 269 65%

15-10/16-10 Average 1,367 281 64% 1,167 167 53%

13-34 Pad Average 949 376 70% 763 271 64%

(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) Extreme limited entry completion w ith 5 clusters per frac/stage.

IP30 IP90 IP180

October 2019

Stable Ultra-Rich Liquids Yields

$2 $2 $2

$7 $7 $6

$6 $6 $6

$18 $21

$29

-

10.00

20.00

30.00

40.00

50.00

East All Wells West

Re

ve

nu

e (

$/B

OE

)

Royalties Opcosts Transportation Operating netback

IP90 CGR = 131

IP90 CGR = 207

INCREASING NETBACKS

17

% Change

West vs East

Revenue 30%

Royalty 30%

Operating costs (16%)

Transportation (7%)

Netback 61%

1. Based on US$55 WTI, US$2.80 NYMEX gas and 2019 estimated field differentials, operating costs and transportation costs per unit for each product stream and average royalty rates.

2. See Non-IFRS measures in the Advisories.

Corporate Netbacks Increase with Addition of Higher Condensate Yield Wells

Impact of Production Composition on IP90 Operating

Netback for Bigstone Montney1

IP90 CGR

= 80

2

October 2019

0

200

400

600

800

1,000

1,200

1,400

1,600

1,800

2,000

0

20

40

60

80

100

120

140

160

180

200

San

d P

laced

(lb

/hz f

t)

Pla

nn

ed

Sta

ges

Planned stages Sand placed

18October 2019

Montney Frac Generation Design Evolution

CRACKING THE COMPLETION CODE AT WEST BIGSTONE

Evolution to more stages and

sand moving to West Bigstone

More at West - less at East

Optimizing frac sizes to

maximize capital efficiency

Successful results of 65 and 80

stage hybrid fracs at West

Bigstone

On-going testing of limited entry

cased hole completions

$0

$5,000

$10,000

$15,000

$20,000

2012 2013 2014 2015 2016 2017 2018

$/b

oep

d

Montney Drill & Complete Capital Efficiency

IP30 IP90

PAD OPERATIONS WILL LOWER DRILLING COSTS

October 2019 19

DEE 13-34-60-24W5 pad operation

Drilling Cost Savings Opportunities

$3,950

$3,061

$2,000

$3,000

$4,000

$5,000

Base

11

4 v

s 1

39

tie

ba

ck

Le

ase F

ue

l

Surf

ace H

yd

raulic

s

Inte

rme

dia

te H

yd

raulic

s

Ma

in n

o r

eam

Wate

r d

rill

main

La

ndin

g J

oin

t

FB

We

llhea

d

PB

R n

o p

olis

h

Walk

ing R

ig

Ce

men

ted lin

er

vs P

ackers

Inte

rme

dia

te n

o r

ea

m

Full

Savin

gs

Near Term TargetP50 Case: $3.55MM

Targeting 20 - 25 percent

reduction in drilling costs

on future multi-well pads

Pe

r w

ell

dri

llin

g c

os

ts (

M$

)

PAD OPERATIONS WILL LOWER COMPLETION COSTS

October 2019 20

DEE 60,000 m3 frac water storage cell

Frac water storage cell now

operational reducing water

handling costs

In-field water disposal facility

now operational reducing

trucking and disposal costs

$4,908

$3,383

$2,000

$3,000

$4,000

$5,000

$6,000

Cu

rren

t 4-w

ell

pa

d 4

0 s

tag

e…

in-f

ield

flo

wback

dis

posal

30

sta

ge

EL

E

clu

ste

rdia

gnostics

elim

inate

dis

so

lvable

…

pro

ppan

tsourc

ing

bi-

fuel

ele

ctr

ify

sourc

e w

ate

rin

frastr

uctu

re

wa

ter

re-u

se

6-w

ell

pad

eff

icie

ncie

s

Fin

al 30 S

tage

Well

w/s

am

e…

Pe

r w

ell

co

mp

leti

on

co

sts

(M

$)

Near Term Target

P50 Case: $3.76MM

Targeting 20 - 25 percent

reduction in completion costs

on future multi-well pads

Completion Cost Savings Opportunities

PAD OPERATIONS WILL DRIVE CAPITAL EFFICIENCIES

21

Cost effective frac design innovations driving lower F&D costs:

Drilling and completion costs lower on multi-well pad operations

Increasing condensate rates/yields

Increasing ultimate recoveries of condensate and natural gas

$0

$10

$20

$30

$40

$50

$60

$70

2012 2013 2014 2015 2016 2017 2018 2019 2020

Cu

mu

lati

ve F

&D

($/b

oe)

Delphi Energy Corp.Full-Cycle Cumulative Montney Finding & Development Costs

Proved Developed Producing Total Proved Total Proved plus Probable

East Bigstone

Exploration and DelineationEast Bigstone

Development

West Bigstone

Exploration and DelineationWest Bigstone

Development

October 2019

45

9

6 6

15

12

4

2012 2013 2014 2015 2016 2017 2018 1H 2019

61 wells drilled LTD

BIGSTONE MONTNEY GROWTH

October 2019 22

Montney Production Growth

0

2,000

4,000

6,000

8,000

10,000

2012 2013 2014 2015 2016 2017 2018 H1 2019

Boe/d

Gas Liquids Non-Montney

Montney Wells Drilled & On Production

Montney 2P Reserve Growth

Montney asset growth funded largely

through cash flow (47%) and non-core

asset dispositions (28%)

Life-to-date (LTD) capital includes

$618 mm DCE&T

$43 mm land / acquisitions

148 gross sections of land acquired

$100 mm LTD facility infrastructure build out

Ownership in 100+ mmcf/d field gathering

and plant processing capacity

0

20,000

40,000

60,000

80,000

2012 2013 2014 2015 2016 2017 2018

Re

se

rve

s (

mb

oe

)

Montney Other

2P mboe CAGR 48%

NPV10 CAGR 23%Liquids CAGR 47%

Nat Gas CAGR 35%

RECAPITALIZATION

TRANSACTION

OVERVIEW

23October 2019

TRANSACTION INTRODUCTION

24

Reduces bank debt, extends maturity of CEL Notes and provides a full capital solution to further develop the Company’s high quality

Bigstone asset

$30 million treasury offering of Equity Subscription Receipts (“ESRs”) backstopped by Luminus up to $28 million

A concurrent $16.5 million ($22 million of face value) treasury offering of CEL Note subscription receipts (“NSRs”) backstopped to

$15 million by Luminus

Proceeds will be used to fund the Company’s 2020 winter capital program at the Company’s West Bigstone liquids-rich Montney

property or for consolidation of the Bigstone area through acquisitions

A Plan of Arrangement to approve the Offering and extend the maturity date of the CEL Notes to April 2023 (from July 2021

currently) and consolidate the common shares outstanding on a 15 for 1 basis

Sale of excess Alliance transportation provided $11.5 million net proceeds

The recapitalization transaction emphasizes Luminus’ support for Delphi through the committed $43 million backstop

Delphi has entered into a recapitalization transaction with Luminus Management, LLC (“Luminus”) backstopping a

treasury equity and Collateralized Exchange Listed (CEL) Note offering for $46.5 million of aggregate gross proceeds,

comprised of the following components (the “Offering”)

Strengthened Delphi with Greater Financial Flexibility

Reduced Bank Debt

Bank debt reduced by

approximately $35 mm (42%)

Enhanced Capital Availability

$52.2 mm of new net capital prior to a

$25 mm reduction in senior bank line

Durable and Sustainable

West Bigstone development

Participate in area consolidation

October 2019

TRANSACTION HIGHLIGHTS

25

Raises $40.7 million (net) through a combination of debt and equity and an additional

$11.5 million from the sale of excess Alliance transportation.

Improves the credit quality of the Company by extending the maturity date of the Notes

to April 2023 (from July 2021)

Allows Delphi to continue the Montney development through the drilling of two 3-well

(net) pads at West Bigstone in early 2020 or consolidation of the Bigstone area

Improvements in the Company’s capital structure and credit quality are expected to

strengthen the Company’s equity valuation and facilitate the continued execution of the

business plan

The recapitalization transaction sends a strong message to the market that Delphi has a

supportive shareholder base and access to capital for development or acquisitions

Maintain Pace of

Development or

Acquisitions

Improved Credit

Status

Strengthen Equity

Valuation Metrics

Illustration of

Financial

Sponsorship

The Offering and Arrangement provide Delphi with a full capital solution to increase its financial

flexibility and strengthen its future growth prospects, for the benefit of all stakeholders

New Capital

October 2019

2019 / 2020 OUTLOOK

26October 2019

Near term Objectives

Strengthen Delphi’s financial position with an improvement in Delphi’s

liquidity position, its cost of capital and the going concern nature of its

business

– Address the Senior Lenders’ borrowing base redetermination

pressures

– Extend the non-revolving debt maturity to April 2023

– Reduce bank debt while replacing/increasing producing reserves

– Provide the working capital to carry out a sustainable 2019/2020

winter capital program

– Provide the shareholders the opportunity to realize potential equity

appreciation from current levels through further development of its

core asset as well as consolidation opportunities

Beyond the Recapitalization Plan

Remain focused on operational and capital efficiencies and return on

capital:

Continued condensate production/reserve growth efforts driving

value creation in an uncertain natural gas market

Continued focus on operating and G&A controllable cost

reductions

Continued active hedging program to mitigate manage commodity

price risk

Identify, pursue, participate in consolidation opportunities with

increased financial flexibility

APPENDIX

27October 2019

ADVISORIES

Forward-Looking Statements and Information

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: the amount of proceeds to be raised under the

Offering; the use of proceeds from the Offering; the satisfaction of certain conditions of the Offering; the completion of the Offering and the timing thereof; the timing and

completion of the distribution of the Subscription Receipts pursuant to the Offering; the listing of the common shares issuable on exercise of share purchase warrants to be

issued by the Company; the timing and completion of the sale and permanent assignment by the Company of 16 mmcf/d of its firm full-path service on the Alliance pipeline

system and the use of proceeds therefrom; anticipated results from the Company’s corporate recapitalization strategy, including the Company’s ability to reduce leverage,

increase capital availability, increase liquidity, improve credit status, strengthen growth prospects and increase financial flexibility; planned drilling, exploration and

development, including the timing and completion of drilling, testing and completion of two 3-well pads at the Company’s West Bigstone property and the spudding of three

additional wells at the Company’s West Bigstone property on the second pad, and the results thereof; the Company’s financing strategy; the performance characteristics of

the Company’s oil and natural gas properties; the Company’s business prospects and strategy and its ability to continue to execute on its business plan; forecast annual

gross sales and EBITDA, year-end total debt, leverage and coverage ratios, available liquidity, annual and fourth quarter production levels and adjusted funds flow plus

proceeds and capital expenditures, in each case in 2019 through 2021; forecast adjusted funds flow sensitivity in 2020 and 2021; pro forma trading valuations following

completion of the proposed recapitalization transactions; anticipated reduction in frac hits as a result of pad drilling; anticipated reduction in costs and liner problems/failures

through the use of pad completions with cased hole liners; estimated corporate netbacks in the Company’s Bigstone Montney wells; economics/metrics related to

hypothetical type wells in Bigstone Montney, including years to payout, internal rate of return, finding and development costs per barrel of oil equivalent, target capital and

initial sales production for the first 30 and 365 days; and expected capital efficiencies resulting from pad drilling, including lower finding and development costs, increasing

condensate rates/yields and increasing ultimate recoveries of condensate and natural gas. 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.

28October 2019

ADVISORIES

The following are certain material assumptions on which the forward-looking statements and information contained in this presentation are based: the successful completion

of the Offering on the terms and at the time expected; the timely receipt of required regulatory and other approvals and that no event will occur that would trigger termination

rights in respect of the Offering; 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; produc tion 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; Delphi’s ability to market oil and natural gas successfully to current and new customers; future well production rates; the

performance of existing wells; the success of drilling new wells; the capital availability to undertake planned activities; and the Company’s business and acquisition strategy,

the criteria to be considered in connection therewith and the benefits to be derived therefrom. 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. Certain additional assumptions reflected in the

Montney economic model included on slide 22 of this presentation are set forth under the heading “Montney Economic Model Assumptions” below. 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. The purpose of

this financial outlook is to provide readers with disclosure regarding the Company’s reasonable expectations as to the anticipated results of its proposed business activities.

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.

29October 2019

ADVISORIES

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, failure to complete the Offering in all material respects

in accordance with the expected terms or at all; a reduction in the borrowing base under the Company’s senior credit facility upon the completion of one or more future

borrowing base redeterminations and reviews; a reduction in the borrowing base under the Company’s senior credit facility below the amount drawn at the time of the

borrowing base redetermination and review; general global economic and business conditions including the effect, if any, of a potential economic slowdown in the U.S.

and/or Canada; 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 required by applicable securities laws. The forward-looking statements contained in this presentation are expressly qualified

in their entirety by this cautionary statement.

30October 2019

ADVISORIES

Montney Economic Model Assumptions

The following assumptions are reflected in the Montney economic model included on slide 22 of this presentation: (1) Flat pricing: NYMEX $2.80/mmbtu USD, $3.71/mmbtu

CDN; WTI $55.00/bbl USD; (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. (5)

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.

Non-IFRS Measures

This presentation contains certain terms which do not have any standardized meanings prescribed by IFRS and are therefore unlikely to be comparable to similar measures

presented by other issuers. None of these measures is used to enhance the Company’s reported financial performance or position. With the exception of EBITDA, adjusted

funds flow, adjusted working capital, net debt, there are no comparable measures to these Non-IFRS measures in accordance with IFRS. The following Non-IFRS measures

are considered to be useful as complementary measures in assessing Delphi’s financial performance, efficiency and liquidity :

• "EBITDA" is net earnings (loss) for a fiscal period adjusted for financing costs, certain specific unrealized and non-cash transactions and acquisition and disposition

activity. Net earnings (loss) is the most comparable measure under IFRS to EBITDA.

• “Annualized EBITDA” is used for covenant calculation purposes and is calculated based on the terms and definitions set out in the senior credit facility agreement which

adjusts net earnings (loss) for financing costs, certain specific unrealized and non-cash transactions and acquisition and disposition activity. Annualized EBITDA is

calculated on an annualized basis based on the last two completed quarters. Net earnings (loss) is the most comparable measure under IFRS to EBITDA.

• “Adjusted funds flow” is cash flow from operating activities before decommissioning expenditures and changes in non-cash working capital from operating activities.

Management uses adjusted funds flow to analyze performance and considers it a key measure as it demonstrates the Company’s ab ility to generate the cash necessary to

fund future capital investments, abandonment obligations and to repay debt. The most comparable measure of adjusted funds flow to an IFRS measure would be cash flow

from operating activities.

• “Operating netback” is crude oil and natural gas sales plus realized gains (losses) on financial instruments and marketing income less royalties, operating and

transportation costs. Management considers operating netbacks per boe an important measure of profitability relative to current commodity prices and costs of production.

• “Adjusted working capital” is current assets and current liabilities excluding the current portion of the fair value of the financial instruments. This definition is consistent with

the definition used in calculating the Company’s compliance with its working capital ratio covenant and is used by the Company in determining its net debt.

31October 2019

2300, 333 – 7th Avenue SW

Calgary, Alberta T2P 2Z1

P (403) 265-6171

F (403) 265-6207

info@delphienergy.ca

www.delphienergy.ca

32October 2019