SEPTEMBER 10, 2019
SEPTEMBER PRESENTATION CORPORATE OVERVIEW ITS BEEN A ROUGH RIDE - - PowerPoint PPT Presentation
SEPTEMBER PRESENTATION CORPORATE OVERVIEW ITS BEEN A ROUGH RIDE - - PowerPoint PPT Presentation
SEPTEMBER 10, 2019 SEPTEMBER PRESENTATION CORPORATE OVERVIEW ITS BEEN A ROUGH RIDE CORPORATE INFORMATION SHARE PRICE PERFORMANCE Ticker Symbol TSX:DEE Basic Shares Outstanding (mm) 185.5 S&P/TSX Market Capitalization (mm) $22.3
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
- f outstanding Letters of Credit
$60 $70 $80 $90 $100 $110 Q3/18A Q4/18A Q1/19A Q2/19A Q3/19E Q4/19E LC's Debt & WC Bank Line
Net Bank Debt ($ mm) (inc/ working capital)
SENIOR CREDIT FACILITY
4 well Pad Project On Production Q2/19
SHARE PRICE PERFORMANCE
Liquids-Rich Montney Group 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
- perating 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
- ffsets 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 Production Competitor Multi-Well Pad Waiting on Completion Competitor License Section 10 4 Well Pad On Production 15-10 and 16-10 On Production
WEST BIGSTONE: SUCCESS IN LOWER LA YER 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 Completion Competitor License Section 10 4 Well Pad On Production
DEE XTO
200 400 600 800 1,000 1,200 1,400 1,600 1,800 2,000 20 40 60 80 100 120 140 160 180 200
Sand Placed (lb/hz ft) Planned Stages
Planned stages Sand placed
6 September 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 $/boepd
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
- ffsetting 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
- f 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 15-30 11-17 15-21 13-30 2-1 2-7 8-21 16-15 3-26 13-23 16-27 12-27 16-24 13-24 14-30 14-24 14-27 13-21 15-23 14-11 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
50 100 150 200 250 50 100 150 200 250 300 350 IP180 CGR (bbl/mmcf sales) IP30 CGR (bbl/mmcf sales)
Delphi Bigstone Montney - IP180 CGR vs. IP30 CGR
West Type Well - Stabilized CGR Type 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 30 60 90 120 150 180 210 240 270 Raw Gas (mcf/d) and Field Condensate (bbl/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 Condy
10 100 1,000 10,000 30 60 90 120 150 180 210 240 270 300 330 360 Raw Gas (mcf/d) and Field Condensate (bbl/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 30 60 90 120 150 180 210 240 270 Raw Gas (mcf/d) and Field Condensate (bbl/d) Producing Days
West Bigstone 15-10-60-24W5
15-10 Gas 15-10 Field Condy Rich Type Curve Gas Rich Type Curve Field Condy
10 100 1,000 10,000 30 60 90 120 150 180 210 240 270 300 330 360 390 420 450 Raw Gas (mcf/d) and Field Condensate (bbl/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 $28
- 10.00
20.00 30.00 40.00 50.00 East All Wells West Revenue ($/BOE) 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 Flow 47% Dispositions 28% Equity 11% Debt 14%
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
$ millions
BIGSTONE MONTNEY GROWTH
September 2019 11
Montney Production Growth
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)
4 5 9 6 6 15 12
2012 2013 2014 2015 2016 2017 2018
Montney Wells brought on Production Montney Reserves (mboe)
5,000 10,000 15,000 20,000 2012 2013 2014 2015 2016 2017 2018
Reserves (mboe)
Proved Developed Producing
Montney Other
20,000 40,000 60,000 80,000 2012 2013 2014 2015 2016 2017 2018
Reserves (mboe)
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 $70 2012 2013 2014 2015 2016 2017 2018 2019 2020 Cumulative F&D ($/boe)
Delphi Energy Corp. Full-Cycle Cumulative Montney Finding & Development Costs
Proved Developed Producing Total Proved Total Proved plus Probable
East Bigstone Exploration and Delineation East Bigstone Development West Bigstone Exploration and Delineation West 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
- perational 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 K3 Alliance/TCPL REPSOL Edson TCPL
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
- f 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 $23 million (1)
(1.50) (1.00) (0.50)
- 0.50
1.00 AUG 19 DEC 19 APR 20 AUG 20 DEC 20 APR 21 AUG 21 DEC 21 APR 22 AUG 22 DEC 22 APR 23 AUG 23 DEC 23 AECO-CHICAGO Basis (US$/mmbtu)
- Arb. (C$/mcf)
- 1.0
2.0 3.0 4.0 5.0 6.0 7.0 8.0 AUG-DEC 2019 2020 2021 2022 2023
Incremental Cash Flow (C$ 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 DEE Montney VII NVA KEL SRX CR BIR AAV
Netback(1) 2018
Operating netback Royalties Operating Transportation % Liquids (Total) % Condensate
2019 OUTLOOK
25 September 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
- ptions 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
- f 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 37 1,840 78 1,407 66 1,112 55 805 57 14-24(3) 3rd 37 1,119 132 976 92 792 76 585 65 14-27(3) 3rd 37 1,414 140 1,280 97 1,082 83 835 70 13-21(3) 3rd 37 1,204 252 1,077 194 962 166 679 172 15-23 3rd 37 1,153 93 909 66 779 54 612 47 14-11 3rd 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 relate to future events or the Company’s future performance and are based upon the Company’s internal assumptions and expectations. All statements other than statements of present or historical fact are forward-looking statements. Forward-looking statements are often, but not always, identified by the use of any of the words “expect”, “anticipate”, “continue”, “estimate”, “may”, “will”, “should”, “believe”, "intends”, “forecast”, “plans”, “guidance”, “budget” and similar expressions. More particularly and without limitation, this presentation contains forward-looking statements and information relating to petroleum and natural gas production estimates and weighting, projected crude
- il and natural gas prices, future exchange rates, expectations as to royalty rates, expectations as to transportation and operating costs, expectations as to general and
administrative costs and interest expense, expectations as to capital expenditures and net debt, planned capital spending, future liquidity and Delphi’s ability to fund ongoing capital requirements through operating cash flows and its credit facilities, supply and demand fundamentals for oil and gas commodities, timing and success of development and exploitation activities, cash availability for the financing of capital expenditures, access to third-party infrastructure, treatment under governmental regulatory regimes and tax laws and future environmental regulations. Furthermore, statements relating to “reserves” are deemed to be forward-looking statements as they involve the implied assessment, based on certain estimates and assumptions that the reserves described can be profitable in the future. The forward-looking statements and information contained in this presentation are based on certain key expectations and assumptions made by Delphi. The following are certain material assumptions on which the forward-looking statements and information contained in this presentation are based: the stability of the global and national economic environment, the stability of and commercial acceptability of tax, royalty and regulatory regimes applicable to Delphi, exploitation and development activities being consistent with management’s expectations, production levels of Delphi being consistent with management’s expectations, the absence of significant project delays, the stability of oil and gas prices, the absence of significant fluctuations in foreign exchange rates and interest rates, the stability of costs of oil and gas development and production in Western Canada, including
- perating costs, the timing and size of development plans and capital expenditures, availability of third party infrastructure for transportation, processing or marketing of oil
and natural gas volumes, prices and availability of oilfield services and equipment being consistent with management’s expectations, the availability of, and competition for, among other things, pipeline capacity, skilled personnel and drilling and related services and equipment, results of development and exploitation activities that are consistent with management’s expectations, weather affecting Delphi’s ability to develop and produce as expected, contracted parties providing goods and services on the agreed timeframes, Delphi’s ability to manage environmental risks and hazards and the cost of complying with environmental regulations, the accuracy of operating cost estimates, the accurate estimation of oil and gas reserves, future exploitation, development and production results and Delphi’s ability to market oil and natural gas successfully to current and new customers. Additionally, estimates as to expected average annual production rates assume that no unexpected outages occur in the infrastructure that the Company relies on to produce its wells, that existing wells continue to meet production expectations and any future wells scheduled to come on in the coming year meet timing and production expectations. Commodity prices used in the determination of forecast revenues are based upon general economic conditions, commodity supply and demand forecasts and publicly available price forecasts. The Company continually monitors its forecast assumptions to ensure the stakeholders are informed of material variances from previously communicated expectations. Financial outlook information contained in this presentation about prospective results of operations, financial position
- r cash flows is based on assumptions about future events, including economic conditions and proposed courses of action, based on management’s assessment of the
relevant information currently available. Readers are cautioned that such financial outlook information contained in this presentation should not be used for purposes other than for which it is disclosed. Although the Company believes that the expectations reflected in such forward-looking statements and information are reasonable, it can give no assurance that such expectations will prove to be correct and such forward-looking statements should not be unduly relied upon. Since forward-looking statements and information address future events and conditions, by their very nature they involve inherent known and unknown risks and uncertainties. Delphi’s actual results, performance or achievements could differ materially from those expressed in, or implied by, these forward-looking statements and, accordingly, no assurance can be given that any of the events anticipated by the forward-looking statements will transpire or occur, or if any of them do so, what benefits Delphi will derive therefrom. Should one or more of these risks or uncertainties materialize, or should assumptions underlying forward-looking statements prove incorrect, actual results may vary materially from those currently anticipated due to a number of factors and risks. These include, but are not limited to, the risks associated with the oil and gas industry in general such as
- perational risks in development, exploration and production, delays or changes in plans with respect to exploration or development projects or capital expenditures, the
uncertainty of estimates and projections relating to production rates, costs and expenses, commodity price and exchange rate fluctuations, marketing and transportation, environmental risks, competition from others for scarce resources, the ability to access sufficient capital from internal and external sources, changes in governmental regulation of the oil and gas industry and changes in tax, royalty and environmental legislation. Additional information on these and other factors that could affect the Company’s operations or financial results are included in the Company’s most recent Annual Information Form and other reports on file with the applicable securities regulatory authorities and may be accessed through the SEDAR website (www.sedar.com). Readers are cautioned that the foregoing list of factors is not exhaustive. Furthermore, the forward-looking statements contained in this presentation are made as of the date of this presentation for the purpose of providing the readers with the Company’s expectations for the coming year. The forward-looking statements and information may not be appropriate for other purposes. Delphi undertakes no obligation to update publicly or revise any forward-looking statements or information, whether as a result of new information, future events or otherwise, unless so required by applicable securities laws. The forward-looking statements contained in this presentation are expressly qualified in their entirety by this cautionary statement.
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FORWARD-LOOKING STATEMENTS AND IMPORTANT NOTES
The following criteria reflects Montney economic modeling assumptions herein the presentation. 1. Flat pricing: NYMEX $2.80/mmbtu US, $3.59/mmbtu CDN; WTI $65.00/bbl USD; C5 $78.77/bbl CDN. 2. Type Well stabilized field condensate beyond month six is 45 bbl/mmcf sales; Rich Type Well stabilized field condensate production beyond month one is 103 bbl/mmcf sales. 3. C3: Propane, C4: Butane, C5: Pentane. Gas plant recovered natural gas liquids estimated at 44 bbl/mmcf sales. 4. Type Well reserves and production performance are internal management estimates and were prepared by a qualified reserves evaluator in accordance with the COGE
- Handbook. 21 horizontal, toe-up Montney wells at East Bigstone with at least 30 stage fracs were time normalized, averaged and used to determine a proved plus probable
reserve estimate. 5. Six horizontal Montney wells at West Bigstone were time normalized, averaged and used to determine a proved plus probable reserve estimate. 6. Type well reserve and production estimates are used for illustrative purposes and internal corporate planning and may not reflect the actual performance of future wells. Economics are half cycle and include target capital to drill, complete, equip and tie-in. No costs for land, central facilities, field gathering infrastructure, corporate costs, etc. are included. For further details on the completion and clean-up test results of the 15-19-59-23W5 well, please see the Company’s press release dated January 16, 2018. This presentation discloses the Company’s future potential drilling opportunities. Unbooked locations are internal estimates based on the Company’s prospective acreage and an assumption as to the number of wells that can be drilled per section based on industry practice and internal review. Unbooked locations do not have attributed reserves or resources (including contingent and prospective). Unbooked locations have been identified by management as an estimation of the Company’s multi-year drilling activities based on evaluation of applicable geologic, seismic, engineering, production and reserves information. There is no certainty that the Company will drill all unbooked drilling locations and if drilled there is no certainty that such locations will result in additional oil and gas reserves, resources or production. The drilling locations
- n 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.
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2300, 333 – 7th Avenue SW Calgary, Alberta T2P 2Z1 P (403) 265-6171 F (403) 265-6207 info@delphienergy.ca www.delphienergy.ca
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