32
SEPTEMBER 10, 2019 SEPTEMBER PRESENTATION
SEPTEMBER 10, 2019
SEPTEMBER PRESENTATION
CORPORATE OVERVIEW – IT’S BEEN A ROUGH RIDE
September 2019 2
CORPORATE INFORMATION
Ticker Symbol TSX:DEE
Basic Shares Outstanding (mm) 185.5
Market Capitalization (mm) $22.3
Bank Debt (1) / Credit Facility (mm) $85.7/ $100.0
5 Year Senior Secured Notes (mm)
Maturity Date: July 2021
$105.0
(1) Bank debt as of March 31, 2019 includes working capital and excludes $7.4 million of outstanding Letters of Credit
$60
$70
$80
$90
$100
$110
Q3/18A Q4/18A Q1/19A Q2/19A Q3/19E Q4/19E
LC's Debt & WC Bank Line
Net
Ban
k D
ebt
($
mm
)(i
nc/
wo
rkin
g ca
pit
al)
SENIOR CREDIT FACILITY
4 well Pad ProjectOn Production
Q2/19
SHARE PRICE PERFORMANCE
Liquids-Rich MontneyGroup
Down 30 to 75 percent DEE
S&P/TSX
Grande Prairie
Bigstone
Montney
Edmonton
Calgary
BIGSTONE – PROLIFIC, LIQUIDS RICH MONTNEY
September 2019 3
Successful delineation drilling
to the west and south
Successful pad development in
West Bigstone
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:
WEST BIGSTONE: DELINEATION SHIFTS TO DEVELOPMENT
September 2019 4
Ultra-rich West Bigstone:
4 well pad on
production
15-10 and 16-10
offsets are best wells
drilled LTD by DEE
Section 19 and 31
wells are also ultra-rich
condensate wells
Sections 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
WEST BIGSTONE: SUCCESS IN LOWER LAYER COULD DOUBLE INVENTORY
September 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
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
6September 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 result of 65 stage
hybrid frac at 16-10, 15-10 and
03/16-31 at West Bigstone
On-going testing of new ball
drop technologies and extreme
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
MOST RECENT WEST BIGSTONE RESULTS
September 2019 7
13-34-60-24W5 four-well pad
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
Pad drilling will greatly reduce frac hits (offset frac hits impact gas rate more than field condensate rate)
Pad completions with cased hole liners will reduce costs and liner problems/failures
Observing performance over the first 90-180 days will be necessary to determine impacts of the increased
fracture intensity
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)
15-19 5th 2,862 49 1,828 228 1,300 183 974 168 646 165
16-07 5th 2,853 28 607 319 565 208 457 183 352 172
16-10 6th 2,855 64 1,441 317 1,234 181 1,035 150 794 124
16-19 5th 2,860 34 953 245 722 188 569 167 418 153
02/16-31 3rd 2,944 49 1,095 340 800 304 613 279
02/15-19 3rd 2,687 50 998 245 754 199 586 180
15-10 6th 2,963 64 1,294 245 1,100 153 781 158
02/15-10 7th 2,869 80 980 233 852 170
03/16-31 6th 2,938 64 1,173 394 902 312 714 272
14-10 7th 2,945 79 1,171 330 945 238
12-10 8th 2,636 41(3) 756 558 585 408
13-10 8th 2,951 40(3) 886 381 670 269
(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 IP365
INCREASING CONDENSATE YIELDS
September 2019 8
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
10
100
1,000
10,000
0 30 60 90 120 150 180 210 240 270
Raw
Gas (
mcf/
d)
an
d F
ield
Co
nd
en
sate
(b
bl/d
)
Producing Days
West Bigstone 03/16-31-59-23W5
03/16-31 Gas 03/16-31 Field Condy
Rich Type Curve Gas Rich Type Curve Field Condy10
100
1,000
10,000
0 30 60 90 120 150 180 210 240 270 300 330 360
Raw
Gas (
mcf/
d)
an
d F
ield
Co
nd
en
sate
(b
bl/d
)
Producing Days
West Bigstone 02/15-19-59-23W5
02/15-19 Gas 02/15-19 Field Condy
Rich Type Curve Gas Rich Type Curve Field Condy
10
100
1,000
10,000
0 30 60 90 120 150 180 210 240 270
Raw
Gas (
mcf/
d)
an
d F
ield
Co
nd
en
sate
(b
bl/d
)
Producing Days
West Bigstone 15-10-60-24W5
15-10 Gas 15-10 Field Condy
Rich Type Curve Gas Rich Type Curve Field Condy10
100
1,000
10,000
0 30 60 90 120 150 180 210 240 270 300 330 360 390 420 450
Raw
Gas (
mcf/
d)
an
d F
ield
Co
nd
en
sate
(b
bl/d
)
Producing Days
West Bigstone 16-10-60-24W5
16-10 Gas 16-10 Field Condy
Rich Type Curve Gas Rich Type Curve Field Condy
MOST RECENT WEST BIGSTONE RESULTS
September 2019 9
50 stages
64 stages
64 stages
64 stages
frac hit
frac hit
$2 $2 $2
$7 $7 $6
$6 $6 $6
$19 $22$28
-
10.00
20.00
30.00
40.00
50.00
East All Wells West
Re
ve
nu
e
($/B
OE
)
Royalties Opcosts Transportation Operating netback
IP90 CGR
= 131
IP90 CGR
= 207
INCREASING NETBACKS
September 2019 10
% Change
West vs East
Revenue 23%
Royalty 23%
Operating costs (15%)
Transportation (5%)
Netback 46%
(1) Based on US$ 60 WTI, US$2.90 NYMEX gas and 2019 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)
IP90 CGR =
80
Cash Flow47%
Dispositions28%
Equity11%
Debt14%
0
2,000
4,000
6,000
8,000
10,000
$0
$100
$200
$300
$400
$500
$600
2012 2013 2014 2015 2016 2017 2018
Cum Capital Cum Proceeds Production
$ m
illio
ns
BIGSTONE MONTNEY GROWTH
September 2019 11
Montney Production Growth
0
2,000
4,000
6,000
8,000
10,000
2012 2013 2014 2015 2016 2017 2018
Boe/d
Gas Liquids Non-Montney
Liquids CAGR 48%
Nat. Gas CAGR 36%
Funding Bigstone Montney Source of Funding
Montney asset growth funded largely
through cash flow (47%) and non-core asset
dispositions (28%)
Life-to-date (LTD) capital includes
$605 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
$605 million
LTD Capital
Cumulative
Proceeds
CONSISTENT RESERVE GROWTH
September 2019 12
60 wells (45.6 net) drilled
2015/16 focused on infill locations
2017/18 focused on delineating west and south lands
Field Condensate reserves up 12%, 42% & 56% for
PDP, TP & P+P over 2017
LTD Montney P+P FD&A $13.51/boe
LTD Montney field netback $18.57/boe
Montney Development (2012 to 2018)
45
9
6 6
15
12
2012 2013 2014 2015 2016 2017 2018
Montney Wells brought on Production
Montney Reserves (mboe)
0
5,000
10,000
15,000
20,000
2012 2013 2014 2015 2016 2017 2018
Re
se
rve
s (
mb
oe
)
Proved Developed Producing
Montney Other
0
20,000
40,000
60,000
80,000
2012 2013 2014 2015 2016 2017 2018
Re
se
rve
s (
mb
oe
)
Total Proved Plus Probable
Montney Other
PAD DRILLING WILL DRIVE CAPITAL EFFICIENCIES
September 2019 13
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
PAD DRILLING WILL DRIVE CAPITAL EFFICIENCIES
September 2019 14
Targeting 20 - 25 percent reduction in completion costs on future pads
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
DEE Water
Disposal
(10-34-59-21W5)
September 2019 15
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
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
7-11 AMINE PLANT ON-STREAM
September 2019 16
Delphi
52 mmcf/d sour
compression and
dehydration
facility
Delphi
17 mmcf/d amine
plant to sweeten
Montney sour gas
September 2019 17
NEW AMINE PLANT IMPROVES CASH NETBACK
Commissioned May 2018
Up to 17 mmcf/d (11 net) of
raw natural gas
Cash flow increases by about
$0.70/mcf(1) on amine
sweetened gas sold on AECO
Cash flow impact increases
to $0.95/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.
BIGSTONE SWEET GAS PROCESSING PLANT
September 2019 18
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
September 2019 19
Alliance
37 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(2)
TCPL
22 mmcf/d firm service
Low cost service for growth beyond 2018
Delphi/Alliance
Full Path Service to Chicago
(1) Subsequent to sale of 16 mmcf/d of excess Alliance services expected to close on September 3, 2019 (2) 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) (1)
GAS MARKETING
September 2019 20
(1) Based on Q4/18 average daily gas sales of 33.1 mmcf/d (37% AECO).
.
Approximately 60% of natural gas sold in Chicago generating significantly higher pricing than AECO.
AECO exposure is hedged through marketing income earned on excess Alliance firm service.
Reactivation of the Alliance pipeline lateral at Bigstone plant in mid 2020 will increase Chicago sales back
to approximately 90% of total
CONTRACTED ALLIANCE SERVICE IS A VALUABLE ASSET
September 2019 21
(1) Based on strip pricing as of July 10, 2019; includes the effect of the sale of 16 mmcf/d of excess Alliance service expected to close on September 3, 2019
The undiscounted value of the arbitrage between AECO and Chicago netback prices available
through Delphi’s Alliance service is approximately $23 million through 2023.
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 is worth approximately $23 million (1)
(1.50)
(1.00)
(0.50)
-
0.50
1.00
AUG19
DEC19
APR20
AUG20
DEC20
APR21
AUG21
DEC21
APR22
AUG22
DEC22
APR23
AUG23
DEC23
AECO-CHICAGO Basis (US$/mmbtu) Arb. (C$/mcf)
-
1.0
2.0
3.0
4.0
5.0
6.0
7.0
8.0
AUG-DEC2019
2020 2021 2022 2023In
cre
menta
l C
ash F
low
(C
$
mm
)
Firm Service IT Service
PROVEN RISK MANAGEMENT PROGRAM
Majority of near term production is hedged
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
September 2019 22
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 2H 2019 1H 2020 2H 2020
Natural gas (mmcf/d) 15.0 8.8 2.5
Average hedge price (C$/mcf)(2) $3.44 $3.37 $3.29
% of natural gas production
hedged(3)
49% 28% 8%
Crude oil (bbl/d) 2,625 2,000 1,500
Average hedge price (C$/bbl) $87.27 $83.31 $83.12
Propane (bbl/d) 400 100 100
Average hedge price (C$/bbl) $43.97 $42.42 $42.38
% of condensate & NGL production
hedged(3)
75% 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 December 31, 2018
BUILT A DOMINANT 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:
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 118 sections, increasing in well density from NE to SW.
Refer to disclaimer for further details.
September 2019 23
Largest Land Position at Bigstone
NETBACK COMPARISON – SELECT MONTNEY PRODUCERS
September 2019 24
Sources: DEE; Company MD&As(1) Excluding hedges
Condensate yields, total liquids content and operating netbacks are
among the highest in the Montney
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 DEEMontney
VII NVA KEL SRX CR BIR AAV
Netback(1) 2018
Operating netback Royalties Operating Transportation % Liquids (Total) % Condensate
2019 OUTLOOK
25September 2019
Approach
Focused on capital efficiency and return on capital
Capital spending will be funded from cash flow
Strong hedge book for 2019 and into 2020
Condensate growth of 29% in 2018 over 2017
2018 unhedged cash netbacks 51% greater than 2017
Free cash flow in excess of 2019 capital program to be
used to reduce bank debt
Delineation drilling success in 2018 sets up multiple
options for “ultra-rich” condensate locations in 2019
and beyond
First Half 2019
Four well pad results in first half of 2019 are pivotal to 2019/20 planning
$26 million 1H 2019 capital program
Drilled fourth well on the four well pad
Complete and put all four wells on production
Catapult water disposal facility in service in Q2
APPENDIX
September 2019 26
INDIVIDUAL MONTNEY WELL DATA
September 2019 27
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 #DIV/0! #DIV/0! 1,213 48 807 36 557 33 397 31
Average 2nd Gen Frac #DIV/0! #DIV/0! 1,398 86 1,160 72 946 65 719 58
14-30 3rd 0 37 1,840 78 1,407 66 1,112 55 805 57
14-24(3) 3rd 0 37 1,119 132 976 92 792 76 585 65
14-27(3) 3rd 0 37 1,414 140 1,280 97 1,082 83 835 70
13-21(3) 3rd 0 37 1,204 252 1,077 194 962 166 679 172
15-23 3rd 0 37 1,153 93 909 66 779 54 612 47
14-11 3rd 0 42 1,212 106 1,028 65 870 53 642 49
16-09 4th 2,855 40 1,161 121 849 108 685 106 495 100
14-21 3rd 2,788 40 1,606 180 1,258 145 968 128 702 115
16-21 3rd 2,858 40 1,968 134 1,541 102 1,258 103 907 85
15-8 4th 2,740 40 1,243 216 1,118 185 890 152 659 137
15-11 3rd 2,866 40 1,375 80 1,178 54 929 46 656 43
13-15 3rd 2,891 40 1,579 106 1,205 85 943 73 664 69
15-09(3) 3rd 2,864 40 756 196 625 149 504 137 369 122
13-09(3) 4th 2,813 40 895 185 668 164 543 151 477 128
13-17(3) 3rd 2,876 40 562 112 575 69 486 62 367 54
14-09(3) 4th 2,863 40 865 213 677 160 542 139 407 126
16-18(3) 4th 2,881 40 500 182 605 87 519 69 403 60
13-10 4th 2,848 39 1,161 167 1,118 101 843 91 627 79
9-21(3) 4th 2,841 40 899 140 715 109 818 73 667 56
16-12 4th 2,859 39 717 300 618 217 546 191 443 157
9-8 4th 2,574 38 941 202 833 141 661 123 509 113
13-7 4th 2,847 40 753 245 652 189 540 172 415 171
14-15 5th 2,879 49 1,130 139 1,054 99 887 82 666 70
15-19 5th 2,862 49 1,828 228 1,300 183 974 168 646 165
14-10(3) 5th 2,856 47 902 132 790 99 669 84 492 76
16-07 5th 2,853 28 607 319 565 208 457 183 352 172
16-10 6th 2,855 64 1,441 317 1,234 181 1,035 150 794 124
16-11 4th 2,855 50 1,060 90 923 69 734 63 520 61
14-18 4th 2,875 50 1,306 156 1,083 103 852 91 624 80
16-19 5th 2,860 34 953 245 722 188 569 167 418 153
02/16-31 3rd 2,944 49 1,095 340 800 304 613 279
13-18 3rd 2,975 50 1,187 134 986 90 784 76
02/15-19 3rd 2,687 50 998 245 754 199 586 180
15-10 6th 2,963 64 1,294 245 1,100 153 781 158
02/15-10 7th 2,869 80 980 233 852 170
03/16-31 6th 2,938 64 1,173 394 902 312 714 272
14-10 7th 2,945 79 1,171 330 945 238
12-10 8th 2,636 41(4) 756 558 585 408
13-10 8th 2,951 40(4) 886 381 670 269
Average 3 - 8 Gen Frac 2,840 1,120 207 928 152 769 122 581 99
(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.
(4) Extreme limited entry completion w ith 5 clusters per frac/stage.
IP30 IP90 IP180 IP365
MONTNEY ECONOMIC MODEL
September 2019 28
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
AER LICENSEE LIABILITY RATING
September 2019 29
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.
September 2019 30
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 reflect the actual performance of future wells.
Economics are half cycle and include target capital to drill, complete, equip and tie-in. No costs for land, central facilities, field gathering infrastructure, corporate costs, etc.
are included.
For further details on the completion and clean-up test results of the 15-19-59-23W5 well, please see the Company’s press release dated January 16, 2018.
This presentation discloses the Company’s future potential drilling opportunities. Unbooked locations are internal estimates based on the Company’s prospective acreage
and an assumption as to the number of wells that can be drilled per section based on industry practice and internal review. Unbooked locations do not have attributed
reserves or resources (including contingent and prospective). Unbooked locations have been identified by management as an estimation of the Company’s multi-year drilling
activities based on evaluation of applicable geologic, seismic, engineering, production and reserves information. There is no certainty that the Company will drill all
unbooked drilling locations and if drilled there is no certainty that such locations will result in additional oil and gas reserves, resources or production. The drilling locations
on which the Company will actually drill wells, including the number and timing thereof is ultimately dependent upon the availability of funding, regulatory approvals,
seasonal restrictions, oil and natural gas prices, costs, actual drilling results, additional reservoir information that is obtained and other factors. While a certain number of the
unbooked drilling locations have been derisked by drilling existing wells in relative close proximity to such unbooked drilling locations, the majority of other unbooked drilling
locations are farther away from existing wells where management has less information about the characteristics of the reservoir and therefore there is more uncertainty
whether wells will be drilled in such locations and if drilled there is more uncertainty that such wells will result in additional oil and gas reserves, resources or production.
September 2019 31
2300, 333 – 7th Avenue SW
Calgary, Alberta T2P 2Z1
P (403) 265-6171
F (403) 265-6207
www.delphienergy.ca
September 2019 32
