high-margin, liquids-rich production in … 2018... · april 2018 high-margin, liquids-rich...
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April 2018
HIGH-MARGIN, LIQUIDS-RICH
PRODUCTION IN THE WORLD-
CLASS MONTNEY BIGSTONE
REGION
WHY OWN DELPHI…….
Pure play MONTNEY E&P company with WORLD CLASS ASSETS:
Robust well economics driven by:
High condensate rates/stable condensate ratios
Attractive capital costs and efficiencies
Increasing netbacks and margins
Owned infrastructure with available capacity
Premium market access avoiding the AECO/Station 2 price crisis
Excess Chicago/Alliance firm service providing arbitrage opportunity
Superior hedge book mitigating commodity price volatility
Solid balance sheet
April 2018 2
BIGSTONE – SOUTHERN END OF PROLIFIC LIQUIDS
RICH MONTNEY TREND
April 2018 3
Grande Prairie
Bigstone
Montney
Edmonton
Calgary
CORPORATE INFORMATION
Ticker Symbol TSX:DEE
Basic Shares Outstanding (mm) 185.5
Market Capitalization (mm)(1) $181.8
Net Bank Debt (2)
/ Credit Facility (mm) $52.0/ $95.0
5 Year Senior Secured Notes (mm)(3) $90.0
Montney Production Growth
(1) As at March 6, 2018.(2) Bank debt plus working capital deficiency as at December 31, 2017.(3) Face value
0
2000
4000
6000
8000
10000
2013 2014 2015 2016 2017 1H2018
Bo
e/d
Gas Liquids Non-Montney
2018 GUIDANCE FOR FIRST HALF 2018
4April 2018
2018 capital program supported by
significant production and cash flow growth
through 2017
Condensate growth of 77% in Q4/17 over
Q4/16
Cash netbacks in Q4/17 29% greater than
Q4/16
Delineation drilling success sets up multiple
options for “ultra-rich” condensate locations
in 2018 and beyond
Production data from 2017 drilling important
input for 2H/18 planning
First Half 2018 capital program
5 to 7 new wells expected on production in
1H/18 depending on spring breakup timing
1H/18 forecast takes into account production
downtime for new well completions and amine
plant construction/commissioning
Phase 1 Amine plant scheduled for Q2/18
start-up
Second Half 2018 capital program expected
in late Q2/18
Strong return on capital, increased cash flow
largely driven by continued condensate
production growth
2018 First
Half Guidance
Net Capital Program ($ million) $38 - $45
Gross Well Count Drilled (net) 4 (2.6)
Gross Well Count On Production (net) 5 (3.3) – 7 (4.6)
2018 First Half
Guidance
2017 First Half
Actuals % Change
Average Production (boe/d) 9,800 – 10,200 7,336 36
Natural Gas (mmcf/d) 35.0 – 37.0 26.6 35
Field Condensate (bbls/d) 2,450 – 2,550 1,738 44
NGL’s (bbls/d) 1,470 – 1,530 1,160 29
Percent Liquids (%) 40 40 -
Adjusted Funds Flow (“AFF”) $25.0 - $27.0 $15.2 71
Cash Netback (per boe,
excluding hedges) $14.25 $11.43 25
Net Debt (1) (2)$149.0 – $154.0 $90.7 55
Net Debt / Quarterly AFF
(annualized) 2.9 – 3.0 3.0
(1) Based on WTI crude oil price of $62 per barrel, NYMEX Henry Hub natural gas price of $2.80/mmbtu
and FX of 1.27 CAD/USD.
(2) Net debt is defined as the sum of bank debt, senior secured notes and the long term portion of
unutilized take-or-pay contract plus (minus) the working capital deficit (surplus) excluding the current portion
of the fair value of the financial instruments.
GROWING THE DOMINANT LAND POSITION
Continue to identify and pursue
additional consolidation opportunities
Montney land base has grown to
169.5 gross sections (111.3 net)
Significant land position allows for
efficient operations, control over
infrastructure and scalable
development
19+ year drilling inventory* on
approximately 128 of 147
undeveloped sections:
400+ “Extended Reach HZ” locations
equivalent to 800+ “1 mile” industry locations
19 years of drilling inventory assuming a 3 rig
(21 well/year) program
* Based on 4 to 6 laterals per section and 1 to 2 layers across
the 128 sections, increasing in well density from NE to SW.
Refer to disclaimer for further details.
April 2018 5
Largest Land Position at Bigstone
April 2018 6
INFRASTRUCTURE LARGELY IN PLACE
Alliance/TCPL
Pembina
SemCams KA/K3
REPSOL Edson
Alliance/TCPL
Alliance/TCPL
Pembina
SemCams K3
To TCPL
Alliance/TCPL
Pembina
DEE Water Disposal
6,000 bpd capacity
DELINEATING THE LARGE LAND POSITION
April 2018 7
• 15 new wells on-stream in 2017
• 7 new wells completed in 1H 2018
7
WEST BIGSTONE EAST BIGSTONE
D3
D2
D1
B1
C
D1
C
D2
B1
Development & Delineation
100% South Montney Lands
100% drilling success on 52 DEE wells
4 wells drilled in 1H/2018
5 – 7 wells on production in 1H/2018
Three Montney layers proven
productive
Industry active offsetting DEE
13-10 and 14-10 results are positive
Industry de-risking offsetting lands
“Ultra-rich” Condensate yields
Multiple layers to drill
Natural gas is low H2S/sweet
Condensate yields increasing
West Bigstone
Delineation drilling program has
validated Delphi’s Bigstone
Montney’s significant value potential
RECENT WELL RESULTS YIELD EVEN GREATER MARGINS
April 2018 8
Condensate Gas Ratios Improving with Frac Design Changes
Initial Production (IP) Rate Well Performance (1)
Frac Design Generation
Total Sales Field CGR Total Sales Field CGR Total Sales Field CGR Total Sales Field CGR
(boe/d) (bbl/mmcf) (boe/d) (bbl/mmcf) (boe/d) (bbl/mmcf) (boe/d) (bbl/mmcf)
Average 1st Gen 1,213 48 807 36 557 33 397 31
Average 2nd Gen 1,398 86 1,160 72 946 65 719 58
Average 3rd, 4th & 5th Gen 1,133 162 966 120 816 97 696 84
Average west 16-12 & 13-7 wells 735 272 635 203
(1) Average production calculated on operating days, excludes non-producing days. Includes estimated NGL gas plant recoveries. All production numbers represent sales volumes.
IP30 IP90 IP180 IP365
INCREASING NETBACKS
April 2018 9
Condensate on a BOE basis↑ Higher realized price than natural
gas and NGLs
↓ Lower op cost than natural gas
and NGLs
↓ Lower transportation cost than
natural gas
% Change
16-12/13-7 versus Gen 1
Revenue 48%
Royalty 48%
Operating costs (24%)
Transportation (10%)
Netback 112%
(1) Based on US$ 60 WTI, US$2.80 NYMEX gas, 2018 estimated field differentials, operating costs and transportation costs per unit for each
product stream and average royalty rates.
Corporate netbacks increase with addition of higher condensate yield wells
Impact of Production Composition on Operating Netback for
Bigstone Montney(1)
NETBACK COMPARISON – MONTNEY PRODUCERS
April 2018 10
Condensate yields, total liquids content and operating netbacks are among the highest
Operating netbacks continue to increase as:
o Focus on West Bigstone production growth where liquids yields and netbacks are 40 – 50% higher
than corporate average
o Addition of Amine sweetening reduces volumes requiring third-party processing and lowers overall
operating costs
o Legacy production (currently 10% of production and less than 2% of operating income) declines
as a percent of total production
0%
20%
40%
60%
-
5.00
10.00
15.00
20.00
25.00
30.00
35.00
40.00
45.00
DEE Corp DEEMontney
DEEWest
Bigstone
VII NVA KEL CR BIR SRX AAV
Revenue e
xclu
din
g h
edges a
nd o
ther
incom
e
($/b
oe)
Operating Netback Fourth Quarter 2017
Operating netback Royalties Operating Transportation % Liquids (Total) % Condensate
WESTERN-MOST WELLS: HIGHEST CONDENSATE YIELD TO DATE
April 2018 11
• Average IP90 field condensate yield of 203 bbl/mmcf sales
• Both wells completed with 40-stages and ~1,350 lb/ft of sand (4th Generation)
• 6th Generation Frac will consist of 65 distinct frac stages and over 1,800 lb/ft of sand
• Recently drilled 16-10-60-24W5 will be the first to implement this design
Highest initial condensate yield
Shallower initial decline
IMPROVED PARENT / CHILD WELL MANAGEMENT
April 2018 12
• Initial production
performance of 13-9
(and other pad wells)
was below expectations
• It was further impacted
by an offset frac in
October
• A partial mill/clean-out
of the horizontal has
brought production
back in-line with
expectations
Offset FracWell
Intervention
Field Condensate up 66%
Natural Gas up 50%
14 days 18 days
SECURE MARKET ACCESS FOR GROWTH
April 2018 13
Alliance
• 57 mmcf/d of firm and priority interruptible service
• Access to premium pricing via Chicago City Gate
• Approximately 23 mmcf/d in excess of requirements for 2018
• Delphi captures value of excess service through assignment at a premium or marketing activity
TCPL
• 24 mmcf/d firm service
• Low cost service for growth beyond 2018
Delphi/Alliance
Full Path Service to Chicago
(1) Delphi captures the value of excess Alliance firm service either by assigning it to 3rd parties at a premium above cost or by using it to transport
3rd party natural gas purchased in Alberta/BC and sold in Chicago to generate marketing income.
Contracted Transportation
Service (mmcf/d)
GAS MARKETING IN 2018 – 100% SHELTERED FROM AECO CARNAGE
April 2018 14
(1) Estimates are based on average daily gas sales of 38 mmcf/d.
(2) Based on CAD/US FX of 1.25. Comprised of 5,250 mmbtu/d at US$2.75 per mmbtu and 14,583 mmbtu/d at C$4.00 mmbtu. The Chicago-
NYMEX basis is fixed at an average of US$(0.21) per mmbtu on 19,014 mmbtu/d.
(3) Based on an average of 12 mmcf/d of excess firm service on Alliance.
(4) Assumes that Delphi captures 75% of arbitrage between Chicago and AECO.
• Over 90% of natural gas sold in Chicago generating significantly higher
netback pricing than AECO.
• Approximately 60% of Chicago sales volumes are hedged with NYMEX
swaps at an average price of US$ 3.08 (C$3.85) per mmbtu(2).
• Minimal AECO exposure is hedged through premiums earned on
assignment of excess Alliance firm service.
Increase in
spread between
AECO and
Chicago
Change in
AECO revenue
($ mm/year)
Change in
premiums
earned on
excess Alliance
service (3)
($mm/year)
Change in
cash flow
($mm/year)
US$0.20 /
mmbtu
(0.3) 0.8 0.5
Delphi Cash Flow Sensitivity to AECO-Chicago Basis
Worsening AECO-Chicago basis increases
Delphi cash flow in 2018
CONTRACTED ALLIANCE SERVICE IS A VALUABLE ASSET
April 2018 15
(1) Value of arbitrage between AECO and Chicago available through all of Delphi’s Alliance service
(2) Based on strip pricing as of January 12, 2018
• The undiscounted value of the arbitrage between AECO and Chicago netback prices available
through all of Delphi’s Alliance service is approximately $40 million over the next 4 years(2).
Value of AECO-Chicago Arbitrage Available through
Delphi’s Alliance Transportation Service(2)
Arbitrage between AECO and Chicago Available
through Delphi’s Alliance Transportation Service(2)
Delphi’s Alliance service worth approximately $40 million (1)
2018 AND BEYOND – MAINTAINING KEY VALUES
April 2018 16
Delineation drilling results have validated Delphi’s Bigstone Montney’s significant value potential
Superior condensate rich well performance yielding top decile capital efficiencies
World Class Montney Asset
Infrastructure and Operational Control
Land Inventory
Market Access and Hedging Strategy
Operational Performance
Growth utilizing existing major infrastructure, with minimal capital requirements
Operatorship with ownership in strategic infrastructure with strong industry partner relationship
Continued new well innovations resulting in increasing condensate yields and operating margin growth
Operating efficiency gains to come with increased development drilling on pads
Dominant land position with 169.5 sections of Montney opportunity with 19+ years of drilling inventory
Continuing to pursue consolidation opportunities within our core land base
Secured firm service with Alliance to access Chicago gas market for stronger pricing
Excess firm service generating additional cash flow on AECO/Station 2 price weakness
Hedge book mitigates commodity price volatility
FORWARD-LOOKING STATEMENTS
AND IMPORTANT NOTES
The presentation contains forward-looking statements and forward-looking information within the meaning of applicable Canadian securities laws. These statements relateto future events or the Company’s future performance and are based upon the Company’s internal assumptions and expectations. All statements other than statements ofpresent or historical fact are forward-looking statements. Forward-looking statements are often, but not always, identified by the use of any of the words “expect”,“anticipate”, “continue”, “estimate”, “may”, “will”, “should”, “believe”, "intends”, “forecast”, “plans”, “guidance”, “budget” and similar expressions. More particularly and withoutlimitation, this presentation contains forward-looking statements and information relating to petroleum and natural gas production estimates and weighting, projected crudeoil and natural gas prices, future exchange rates, expectations as to royalty rates, expectations as to transportation and operating costs, expectations as to general andadministrative costs and interest expense, expectations as to capital expenditures and net debt, planned capital spending, future liquidity and Delphi’s ability to fund ongoingcapital requirements through operating cash flows and its credit facilities, supply and demand fundamentals for oil and gas commodities, timing and success of developmentand exploitation activities, cash availability for the financing of capital expenditures, access to third-party infrastructure, treatment under governmental regulatory regimesand tax laws and future environmental regulations. Furthermore, statements relating to “reserves” are deemed to be forward-looking statements as they involve the impliedassessment, based on certain estimates and assumptions that the reserves described can be profitable in the future. The forward-looking statements and informationcontained in this presentation are based on certain key expectations and assumptions made by Delphi. The following are certain material assumptions on which theforward-looking statements and information contained in this presentation are based: the stability of the global and national economic environment, the stability of andcommercial acceptability of tax, royalty and regulatory regimes applicable to Delphi, exploitation and development activities being consistent with management’sexpectations, production levels of Delphi being consistent with management’s expectations, the absence of significant project delays, the stability of oil and gas prices, theabsence of significant fluctuations in foreign exchange rates and interest rates, the stability of costs of oil and gas development and production in Western Canada, includingoperating costs, the timing and size of development plans and capital expenditures, availability of third party infrastructure for transportation, processing or marketing of oiland natural gas volumes, prices and availability of oilfield services and equipment being consistent with management’s expectations, the availability of, and competition for,among other things, pipeline capacity, skilled personnel and drilling and related services and equipment, results of development and exploitation activities that are consistentwith management’s expectations, weather affecting Delphi’s ability to develop and produce as expected, contracted parties providing goods and services on the agreedtimeframes, Delphi’s ability to manage environmental risks and hazards and the cost of complying with environmental regulations, the accuracy of operating cost estimates,the accurate estimation of oil and gas reserves, future exploitation, development and production results and Delphi’s ability to market oil and natural gas successfully tocurrent and new customers. Additionally, estimates as to expected average annual production rates assume that no unexpected outages occur in the infrastructure that theCompany relies on to produce its wells, that existing wells continue to meet production expectations and any future wells scheduled to come on in the coming year meettiming and production expectations. Commodity prices used in the determination of forecast revenues are based upon general economic conditions, commodity supply anddemand forecasts and publicly available price forecasts. The Company continually monitors its forecast assumptions to ensure the stakeholders are informed of materialvariances from previously communicated expectations. Financial outlook information contained in this presentation about prospective results of operations, financial positionor cash flows is based on assumptions about future events, including economic conditions and proposed courses of action, based on management’s assessment of therelevant information currently available. Readers are cautioned that such financial outlook information contained in this presentation should not be used for purposes otherthan for which it is disclosed. Although the Company believes that the expectations reflected in such forward-looking statements and information are reasonable, it can giveno assurance that such expectations will prove to be correct and such forward-looking statements should not be unduly relied upon. Since forward-looking statements andinformation address future events and conditions, by their very nature they involve inherent known and unknown risks and uncertainties. Delphi’s actual results,performance or achievements could differ materially from those expressed in, or implied by, these forward-looking statements and, accordingly, no assurance can be giventhat any of the events anticipated by the forward-looking statements will transpire or occur, or if any of them do so, what benefits Delphi will derive therefrom. Should one ormore of these risks or uncertainties materialize, or should assumptions underlying forward-looking statements prove incorrect, actual results may vary materially from thosecurrently anticipated due to a number of factors and risks. These include, but are not limited to, the risks associated with the oil and gas industry in general such asoperational risks in development, exploration and production, delays or changes in plans with respect to exploration or development projects or capital expenditures, theuncertainty of estimates and projections relating to production rates, costs and expenses, commodity price and exchange rate fluctuations, marketing and transportation,environmental risks, competition from others for scarce resources, the ability to access sufficient capital from internal and external sources, changes in governmentalregulation of the oil and gas industry and changes in tax, royalty and environmental legislation. Additional information on these and other factors that could affect theCompany’s operations or financial results are included in the Company’s most recent Annual Information Form and other reports on file with the applicable securitiesregulatory authorities and may be accessed through the SEDAR website (www.sedar.com). Readers are cautioned that the foregoing list of factors is not exhaustive.Furthermore, the forward-looking statements contained in this presentation are made as of the date of this presentation for the purpose of providing the readers with theCompany’s expectations for the coming year. The forward-looking statements and information may not be appropriate for other purposes. Delphi undertakes no obligationto update publicly or revise any forward-looking statements or information, whether as a result of new information, future events or otherwise, unless so required byapplicable securities laws. The forward-looking statements contained in this presentation are expressly qualified in their entirety by this cautionary statement.
April 2018 17
FORWARD-LOOKING STATEMENTS
AND IMPORTANT NOTESThe following criteria reflects Montney economic modeling assumptions herein the presentation; 1. Strip pricing for 5 years then escalated at 2%/yr thereafter. 2018 prices:
Henry Hub $2.90/mmbtu US, $3.60/mmbtu CDN; WTI $62.39/bbl USD; C5 $79.46/bbl CDN. 2019 Prices: Henry Hub $2.81/mmbtu US, $3.49/mmbtu CDN; WTI $57.96/bbl
USD; C5 $71.93/bbl CDN. 2. Type Well stabilized field condensate beyond month six is 46 bbl/mmcf sales; Rich Type Well stabilized field condensate production beyond
month one is 115 bbl/mmcf sales. 3. C3: Propane, C4: Butane, C5: Pentane. Gas plant recovered natural gas liquids estimated at 44 bbl/mmcf sales. 4. Type Well reserves
and production performance are internal management estimates and were prepared by a qualified reserves evaluator in accordance with the COGE Handbook. Delphi's first
18 horizontal toe up Montney wells at East Bigstone with at least 30 stage fracs were time normalized, averaged and used to determine a proved plus probable reserve
estimate. 5. Rich Type Well Shale gas reserve assumptions are based on year end 2015 GLJ proved plus probable ultimate recoverable assignment of 3.9 bcf for the
102/15-21-60-23W5 well which is the western most horizontal Montney well brought on production at east Bigstone by Delphi as of December 31, 2015. 102/15-21 has a
life to date field condensate to gas ratio (CGR) of 88 bbl/mmcf sales since coming on production in February 2014. Reserve estimates include estimated gas plant recovered
natural gas liquids of 44 bbl/mmcf sales. 6. Reserve and production estimates are used for illustrative purposes and internal corporate planning and may not reflect the
actual performance of future wells. Economics are half cycle and include target capital to drill, complete, equip and tie-in. No costs for land, central facilities, field gathering
infrastructure, corporate costs, etc. are included.
For further details on the completion and clean-up test results of the 15-19-59-23W5 well, please see the Company’s press release dated January 16, 2018.
This presentation discloses the Company’s future potential drilling opportunities. Unbooked locations are internal estimates based on the Company’s prospective acreage
and an assumption as to the number of wells that can be drilled per section based on industry practice and internal review. Unbooked locations do not have attributed
reserves or resources (including contingent and prospective). Unbooked locations have been identified by management as an estimation of the Company’s multi-year drilling
activities based on evaluation of applicable geologic, seismic, engineering, production and reserves information. There is no certainty that the Company will drill all
unbooked drilling locations and if drilled there is no certainty that such locations will result in additional oil and gas reserves, resources or production. The drilling locations
on which the Company will actually drill wells, including the number and timing thereof is ultimately dependent upon the availability of funding, regulatory approvals,
seasonal restrictions, oil and natural gas prices, costs, actual drilling results, additional reservoir information that is obtained and other factors. While a certain number of the
unbooked drilling locations have been derisked by drilling existing wells in relative close proximity to such unbooked drilling locations, the majority of other unbooked drilling
locations are farther away from existing wells where management has less information about the characteristics of the reservoir and therefore there is more uncertainty
whether wells will be drilled in such locations and if drilled there is more uncertainty that such wells will result in additional oil and gas reserves, resources or production.
April 2018 18
APPENDIX
April 2018 19
INDIVIDUAL MONTNEY WELL DATA
April 2018 20
Initial Production (IP) Rate Well Performance (1)
Well(2) Frac Design Horizontal Number
Generation Length of Fracs Total Sales Field Condy Total Sales Field Condy Total Sales Field Condy Total Sales Field Condy
to Gas Yield to Gas Yield to Gas Yield to Gas Yield
(metres) (boe/d) (bbl/mmcf) (boe/d) (bbl/mmcf) (boe/d) (bbl/mmcf) (boe/d) (bbl/mmcf)
Average 1st Gen Frac 2,668 20 1,213 48 807 36 557 33 397 31
Average 2nd Gen Frac 2,572 30 1,398 86 1,160 72 946 65 719 58
14-30 3rd 2,729 37 1,840 78 1,407 66 1,112 55 805 57
14-24(3) 3rd 2,602 37 1,119 132 976 92 792 76 585 65
14-27(3) 3rd 2,887 37 1,414 140 1,280 97 1,082 83 835 70
13-21(3) 3rd 2,781 37 1,204 252 1,077 194 962 166 679 172
15-23 3rd 2,865 37 1,153 93 909 66 779 54 612 47
14-11 3rd 2,846 42 1,212 106 1,028 65 870 53 642 49
16-09 4th 2,855 40 1,161 121 849 108 685 106 495 100
14-21 3rd 2,788 40 1,606 180 1,258 145 968 128 702 115
16-21 3rd 2,858 40 1,968 134 1,541 102 1,258 103 907 85
15-8 4th 2,740 40 1,243 216 1,118 185 890 152
15-11 3rd 2,866 40 1,375 80 1,178 54 929 46
13-15 3rd 2,891 40 1,579 106 1,205 85 943 73
15-09(3) 3rd 2,864 40 756 196 625 149 504 137
13-09(3) 4th 2,813 40 895 185 668 164 543 151
13-17(3) 3rd 2,876 40 562 112 575 69 486 62
14-09(3) 4th 2,863 40 865 213 677 160 542 139
16-18(3) 4th 2,881 40 500 182 605 87 519 69
13-10 4th 2,848 39 1,161 167 1,118 101
9-21(3) 4th 2,841 40 903 137
16-12 4th 2,859 39 717 300 618 217
9-8 4th 2,574 38 941 202 833 141
13-7 4th 2,847 40 753 245 652 189
14-15 5th 2,879 49 1,130 139 1,054 99
15-19 5th 2,862 49 waiting on IP30
14-10 5th 2,856 47 waiting on IP30
16-07 5th 2,853 50 waiting on completion
16-10 6th 2,855 65 waiting on completion
16-11 4th 2,855 50 waiting on completion
14-18 4th 2,875 50 waiting on completion
16-19 5th 2,860 50 waiting on completion
Average 3rd, 4th & 5th Gen Frac 2,821 40 1133 162 966 120 816 97 696 84
(1) Average production calculated on operating days, excludes non-producing days. Includes estimated NGL gas plant recoveries. All production numbers represent sales volumes.
(2) Wells listed chronologically by rig release date.
(3) Initial production restricted.
IP30 IP90 IP180 IP365
4
6
8
6 6
15
7
2012 2013 2014 2015 2016 2017 1H2018
New Montney Wells Producing
MONTNEY ECONOMIC MODEL
April 2018 21
Rich Type Well13-21 Yield 2.5x Type Well at 100 bbl/mmcf
Full cycle (including $4.00 per boe of G&A and interest costs) IRR for the Type Well and the Rich Type Well are
32% and 76% respectively.
Note: See Montney Economic Model Assumptions in the Forward Looking Statement and Important Notes
DEE Type Well
Economics/Metrics - January 12, 2018 Strip Pricing(1)
Type Well Rich Type Well
Payout yrs 1.7 1.1
IRR % 57% 105%
NPV 10 MM$ $5.6 $11.7
PI 1.7 2.5
F&D $/boe $7.21 $6.21
Target Capital
D,C,E&TI MM$ $8.0 $8.0
Initial Sales Production (IP30 - first 30 day average)
Gas mmcf/d 5.1 3.6
Field Condensate(2) bbl/mmcf 97 183
Total Liquids (C3+)(2,3) bbl/mmcf 137 223
Total Liquids (C3+)(2,3) bbl/d 698 806
Total IP30 boe/d 1,550 1,408
IP365 (first 365 day average)
Gas mmcf/d 2.9 2.2
Field Condensate(2) bbl/mmcf sales 62 125
Total Liquids (C3+)(2,3) bbl/mmcf sales 101 165
Total Liquids (C3+)(2,3) bbl/d 296 360
Total IP365 boe/d 783 724
Reserves (sales)
Gas bcf 4.3 4.0
Liquids (C3+)(2,3) mmbbl 0.4 0.6
Total mmboe 1.1 1.3
Bigstone Montney Toe Up Two Section Horizontal Hypothetical Type Wells
30+ stage Slickwater Completion
PROVEN RISK MANAGEMENT PROGRAM
Majority of near term production is
hedged
Event driven natural gas hedging
strategy with a long term view of
relatively balanced supply & demand;
Strategy is proven and repeatable
over 2 - 4 year “peak to trough”
event cycles
Risk management contracts generally
put in place over a 12 - 48 month period
Over an 11 year period risk
management program has:
Realized $113 million in hedging
gains
Increased revenues by 9%
Increased cash flow by 20%
Added $3.65/boe to netback
April 2018 22
Consistent Hedge Performance
-$15
-$10
-$5
$0
$5
$10
$15
$20
$25
$30
$35
2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017E
Hedging Gains/Losses ($millions)
Cold winter lifting natural
gas prices in 2014
Natural gas
price spike in
2008Steady decline of natural
gas prices from 2009 to
2013
Collapse of natural gas and
crude oil prices
Commodity HedgesQ1 2018 Q2 2018 Q3 2018 Q4 2018 2019
Natural gas (mcf/d) 20.0 21.0 21.0 17.4 7.2Average hedge price (C$/mcf) 3.86 3.84 3.84 3.86 3.90
Crude oil (bbl/d) 2,256 2,500 2,100 2,100 600Average hedge price (C$/bbl) 70.50 71.20 72.41 72.41 70.13
2300, 333 – 7th Avenue SW
Calgary, Alberta T2P 2Z1
P (403) 265-6171
F (403) 265-6207
www.delphienergy.ca
April 2018 24