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CORPORATE STRATEGY
PRESENTATION
March 2017
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FORWARD-LOOKING STATEMENTS
AND IMPORTANT NOTES
2
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 futureperformance 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 areoften, 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. Moreparticularly and without limitation, this presentation contains forward-looking statements and information relating to petroleum and natural gas production estimates and weighting, projected crude oil 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 capitalexpenditures 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 andgas 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 regulatoryregimes 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 estimatesand 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 byDelphi. 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, thestability 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 Delphibeing 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 stabilityof costs of oil and gas development and production in Western Canada, including operating costs, the timing and size of development plans and capital expenditures, availability of third party infrastructure fortransportation, 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, weatheraffecting 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 ofcomplying 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 oiland 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 relieson 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 thedetermination 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 assumptionsto ensure the stakeholders are informed of material variances from previously communicated expectations. Financial outlook information contained in this presentation about prospective results of operations, financialposition or cash flows is based on assumptions about future events, including economic conditions and proposed courses of action, based on management’s assessment of the relevant information currently available.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 expectationsreflected 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 orachievements 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-lookingstatements 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-lookingstatements 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 ingeneral such as operational risks in development, exploration and production, delays or changes in plans with respect to exploration or development projects or capital expenditures, the uncertainty of estimates andprojections 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 toaccess 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 andother 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 authoritiesand 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 presentationare 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 otherpurposes. 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 applicablesecurities laws. The forward-looking statements contained in this presentation are expressly qualified in their entirety by this cautionary statement.
The following criteria reflects Montney economic modeling assumptions herein the presentation; 1. Strip pricing for 5 years then escalated at 2%/yr thereafter. 2017 prices: Henry Hub $3.18/mmbtu US, $4.20/mmbtu CDN;
WTI $55.30/bbl USD; C5 $70.91/bbl CDN. 2018 Prices: Henry Hub $3.00/mmbtu US, $3.94/mmbtu CDN; WTI $56.07/bbl USD; C5 $70.70/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 116 bbl/mmcf. 3. C3: Propane, C4: Butane, C5: Pentane. Gas plant recovered natural gas liquids estimated at 40 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 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 90 bbl/mmcf sales since coming on production in February 2014, an initial recoverable proved plus probable reserve CGR
assignment of 85 bbl/mmcf sales (total ultimate recoverable P+P reserves of 1.1 mmboe) and a current CGR (November 2016) of 81 bbl/mmcf sales. Reserve estimates include estimated gas plant recovered natural gas
liquids of 40 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.
March 2017
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KEY VALUE HIGHLIGHTS
Pure Play Montney E&P Company with WORLD CLASS ASSETS AND A TRACK RECORD OF SUCCESS
Substantial drilling inventory on 147 sections of land; 8 sections fully developed
Bigstone Montney economics are attractive in the current commodity price environment
Significant free cash generated at payout
Growth to 2019 will utilize existing major infrastructure, with minimal capital required
Significant ownership and operational position in field facilities and pipelines to support profitable growth
Drilling and completion costs down 33%, operating costs down 30%, since 2014
Added $113 million in cash as a result of an exceptional hedging program
Significant hedged position in place through 2019
Secured firm service with Alliance to access Chicago gas market for better pricing and fewer curtailments
Reduced debt by 30% from the sale of non-core assets – now 100% focused at Bigstone
Replacing PDP reserves with higher netback boe’s than depleting – each $1 spent = $2 returns
Achieving targets within cash flow to accelerate 2017 drilling and production growth with increased liquidity
Moderating short-term pace of spend while preserving long-term growth inventory
Frac innovations and increased condensate yields leading to better margins
Delivering top quartile PDP F&D costs and recycle ratios
Top tier well results and capital efficiencies – 2 mile extended reach drilling improving overall well results
Exceptional management team with a track record of value creation
WORLD CLASS
MONTNEY GROWTH
ASSET
OVERALL
OPERATIONAL
CONTROL
MARKET ACCESS &
EXCEPTIONAL RISK
MANAGEMENT
RESPONSIBLY
MANAGED
PROFITABLE GROWTH
EXECUTIONAL
EXCELLENCE
3March 2017
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CORPORATE SNAPSHOT
2017 GUIDANCE
Average Annual Production (boe/d) 9,000 – 9,500
Q4/17 Production Rate (boe/d) 11,000
Q4/16 7,127
NYMEX Natural Gas Price (US $ per mmbtu) $3.25
WTI Oil Price (US $ per bbl) $55.00
Natural Gas Liquids Price (Cdn $ per bbl) $28.00
Foreign Exchange Rate (US/Cdn) 1.33
Gross Well Count (Net) 13.0 (8.4)
Gross Well Count On Production (Net) 14.0 (9.0)
Net Capital Program ($ million) $65.0 - $70.0
Funds from Operations (“FFO”) ($ million) $52.0 - $57.0
December 31, 2017 Net Debt ($ million) $120.0 - $125.0
Total Debt / Q4 FFO (annualized) 1.4 – 1.6
(1) Bank debt at December 31, 2016 includes Letters of Credit of $6.6 million and working capital.
Grande Prairie
Bigstone
Montney
Edmonton
Calgary
4
CORPORATE INFORMATION
Ticker Symbol TSX:DEE
Basic Shares Outstanding (mm) 155.5
Market Capitalization (mm) $248.0
Bank Debt (1) / Credit Facility (mm) $50.0/ $80.0
5 Year Senior Secured Notes (mm) $60.0
2017 Full Year Guidance
Updated 2016 Full Year Guidance
Variance
Natural Gas (mmcf/d) 32.0 – 35.0 28.0 – 29.0 18%
Field Condensate (bbls/d) 2,100 – 2,200 1,350 – 1,450 54%
NGL’s (bbls/d) 1,400 – 1,500 1,100 – 1,200 26%
Percent Liquids (%) 40 35 14%
March 2017
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DELIVERING EXCEPTIONAL MARGIN GROWTH
5
Condensate yields increasing and improving the cost structure
2017 condensate production forecast to more than double
Condensate yields in recent wells have increased up to 4x
Unhedged field operating netbacks per boe increased by 3x
Source: AltaCorp Capital
2016 Focus on Margin Growth Paid Off
Operating Costs vs. Gas Weight
2016/2015 Q2 Operating Costs vs. Production Mix Relative Change
Increasing Margins
March 2017
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6
POSITIONED TO DELIVER EXCEPTIONAL PER SHARE GROWTH
Improved corporate position to grow production and funds from operations in 2017;
Run rate funds to increase by 20% in 2017, over 2014
Total debt at year end 2017 is forecast to be 30% lower over 2014
Shares outstanding have remained unchanged to date
Positioned to achieve significant production, cash flow and reserve growth over the near and long-term
to the benefit of all stakeholders
2015
Disposition of $62.0 million of non-core assets to focus
on Bigstone Montney
2016
Strengthening capital structure through the issuance of
$60.0 in senior secured notes
$50.0 million Partner Transaction to accelerate drilling
activity and production growth while strengthening the
balance sheet
Establishment of an $80 million Bank Syndicate to
support accelerated growth
Successfully Managed Prolonged Commodity Price Downturn Since Q4 2014
Summary of Creative Initiatives
March 2017
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2012 2013 2014 2015 2016 2017F
68
65
6
Delphi Bigstone Montney Wells Drilled
12-14
MONTNEY GROWTH ACCELERATING IN 2017
Montney Production (boe/d)
0
2,000
4,000
6,000
8,000
10,000
12,000
2012 2013 2014 2015 2016 2017F Q4/17
Growth accelerating through 2017
0
1,000
2,000
3,000
2012 2013 2014 2015 2016 2017F Q4/17
Montney condensate production accelerating with increasing yields
Montney Field Condensate Production (boe/d)
7
Q4/16 to Q4/17 Growth Comparison
Forecast Year Q4 2017 Q4 2016 Variance
Production (boe/d) 11,000 – 11,500 7,127 58%
Production per share (per
million shares)73 45 61%
Q4 FFO ($ million) $18.0 - $20.0 $7.5 - $8.0 145%
Annualized FFO ($ million) $72.0 - $80.0 $30.0 - $32.0 145%
Annualized FFO per share $0.46 - $0.51 $0.20 143%
Cash Netback Including
Hedges ($/boe) $18.00 $12.25 47%
Cash Netback Excluding
Hedges ($/boe)$18.50 $8.75 111%
March 2017
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8
0
50
100
150
200
2008 2009 2010 2011 2012 2013 2014 2015
Producing* Wells by Rig Release DateTotal Wells: 937
Delphi maintains a 100%
success rate
0
20
40
60
80
100
120
Producing Wells by Operator
0
1,000
2,000
3,000
4,000
5,000
IP180 (mcfd raw)418 wells
Bigstone
Karr
Wapiti
Kakwa
Simonette
BIGSTONE – SOUTHERN END OF PROLIFIC LIQUIDS
RICH MONTNEY TREND
Top 3 for 6-Month
Production Rates
Top 10 in # of Montney
Wells Drilled
* 527 Wells with IP90 or greater
Elmworth
March 2017
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DOMINANT LAND POSITION IN BIGSTONE MONTNEY
Largest Land Position at Bigstone
Bigstone Activity by Region
East Bigstone – manufacturing / development
West Bigstone – industry activity derisking
South Bigstone – exploration opportunity
Super-major presence and development
activity; Exxon, Chevron, & ConocoPhillips
operate in the general area
Current Montney land position grown
from 4.0 to 147 gross (90 net) sections
since 2010;
Significant land position allows for
efficient operations, control over
infrastructure and scalable development
8 sections fully developed with
substantial room to grow through drilling
Drilling program moving west into ultra-
rich condensate region
9March 2017
Legend
Delphi continues to identify and
pursue additional land
consolidation opportunities
within the Greater Bigstone area
WEST BIGSTONE
SOUTH BIGSTONE
Other
EAST BIGSTONE
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STRATEGIC INFRASTRUCTURE AT BIGSTONE
Significant Infrastructure In Place
Minimal infrastructure capital required for
growth plans to 25,000 boe/d (net to DEE);
Legacy sour processing capacity available at
SemCAMS K3 and KA; Connected to Alliance, TCPL and Pembina
DEE 7-11 Montney sour dehydration and
compression facility (65% W.I.); Currently 55 mmcf/d capacity
Secured 20 mmcf/d amine plant for Q1/18
start-up
DEE 5-08 Montney sour dehydration and
compression facility (65% W.I.); Current 10 mmcf/d capacity
Adding 25 mmcf/d capacity by Q1/18
DEE 11-03 Sweet processing plant (100% W.I.); Available for sweet West Bigstone Montney
Current 15 mmcf/d capacity
Equipment secured to expand to 30 mmcf/d
Repsol 14-28 Sweet processing plant; Current 85 mmcf/d capacity (DEE 25% W.I.)
Available for amine treated Montney production $4.00
$5.00
$6.00
$7.00
$8.00
$9.00
$10.00
$11.00
$12.00
2012 2013 2014 2015 2016
Op
era
tin
g C
os
ts (
$/b
oe
)
Montney Operating Costs
Operating cost decrease by 30% since 2014
to $5.75/boe in Q3/16
10
DEE 7-11
Sour Montney Facility
55 mmcf/d
To SemCAMSK3 and KA
To TCPL
REPSOL 14-28Sweet Gas Plant
85 mmcf/d
DEE 11-03
Sweet Gas Plant
15 mmcf/d
DEE 5-08
Sour Montney Facility
10 mmcf/d
March 2017
To REPSOLEdson
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MARKET ACCESS ADVANTAGE
11
Exceptional Gas Marketing
Future growth will utilize existing major infrastructure, with minimal capital required
Secured firm service agreement to access larger Chicago gas market for better pricing;
Pricing has been significantly better than AECO
Secured firm service minimizing exposure to curtailments on the TCPL pipeline system
Delphi / Alliance
Full-path service to Chicago
March 2017
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DELPHI / ALLIANCE FIRM TRANSPORTATION SERVICE
12
0.0
10.0
20.0
30.0
40.0
50.0
60.0
70.0
80.0
Dec-1
5
Feb
-16
Apr-
16
Jun
-16
Aug-1
6
Oct-
16
Dec-1
6
Feb
-17
Apr-
17
Jun
-17
Aug-1
7
Oct-
17
Dec-1
7
Feb
-18
Apr-
18
Jun
-18
Aug-1
8
Oct-
18
Dec-1
8
Feb
-19
Apr-
19
Jun
-19
Aug-1
9
Oct-
19
Dec-1
9
Feb
-20
Apr-
20
Jun
-20
Aug-2
0
Oct-
20
Delphi Transportation Capacity on Alliance / TCPL (mmcf/d)
Alliance Firm TCPL Firm
Future TCPL Contract Capacity
Low cost growth beyond 2018
2017 Forecast Annual Natural
Gas Production Rate
Firm service planned out for growth to 25,000 boe/d (net to DEE)
Holding Staged FFPS Service to secure markets for DEE future growth plans
Ongoing temporary assignments of FFPS service on a monthly or term basis
Current temporary and permanent assignments generate premiums over cost
March 2017
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CONSISTENT AND PROVEN RISK MANAGEMENT
PROGRAM
Majority of near term production is
hedged
Event driven natural gas hedging
strategy with a long term view of a
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
Consistent Hedge PerformanceNatural Gas Q2 - Q4/17 2018 2019
Percent Hedged* 65% 46% 21%
Hedge Price (Cdn $/mmbtu) $4.20 $3.88 $3.89
Crude Oil Q2 - Q4/17 2018 2019
Percent Hedged* 42% 14% 14%
Hedge Price (WTI CDN $/bbl) $66.67 $70.00 $70.00
* Based on average 2017 production of 33.5 mmcf/d of natural gas and 2,150 bbls/d of field condensate.
March 2017
-$15
-$10
-$5
$0
$5
$10
$15
$20
$25
$30
$35
2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016
Hedging Gains/Losses ($millions)
Polar Vortex 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
13
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29 BIGSTONE MONTNEY WELLS DRILLED
14
Drilled 5 horizontal wells in 2012;
Average IP30: +1,200 boe/d (19% liquids)
Conventional gelled oil frac designs
Began extended reach laterals of 2,200 m to 3,000
m which improved costs
Drilled 18 horizontal wells from 2013 – 2015;
Average IP30: +1,440 boe/d (30% liquids)
First mover in slickwater hybrid frac design -
improved production performance
Continued innovation of the slickwater frac design
Delineation of East Bigstone focused on high
productivity infill drilling
Drilled 6 horizontal wells in 2016;
Moving west to target higher condensate yields
and increased pay thickness
Company evaluating increased well density from 4
laterals per section to 5 or 6
Significant drilling inventory on 147 sections
for 2017 and beyond with high condensate
yields;
2017 development plan contemplates the drilling
of 13 gross (8.4 net) Bigstone Montney horizontal
wells
Completion, tie-in and well site equipping of 14
gross (9.0 net) wells
Progressive improvements in Drilling Results
Legend
2012-2015 (23 wells)
2016 (6 wells)
2017 YTD (5 wells)
March 2017
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HIGHER CONDENSATE YIELDS BOOSTING ECONOMICS
Larger fracs
Higher pump rates
Higher sand concentrations
Enhanced fracture complexity
Increased condensate yields
Successfully re-frac’d first well
Continuing Frac Innovation
15
93 98 101 106121 132 137 140
180
252
-
50
100
150
200
250
300
Fie
ld C
on
de
ns
ate
Yie
ld (
bb
ls/m
cf)
IP30 Montney Field Condensate
Yields
Frac innovation yielding
more condensate
Netbacks 1.2 to 1.8 times higher
DEE 12-17
2013 Drill
IP30 CGR 62 bbl/mmcf
XTO 2015 Drill
CGR 260 bbl/mmcf
(based on public data)
DEE Type Well
IP30 CGR 98
bbl/mmcf
DEE 13-21
2015 Drill
IP30 CGR 252 bbl/mmcf
ATH 2015 Wells
IP30 CGR
158 to 242 bbl/mmcf
DEE 16-30 Refrac
IP30
CGR 101 bbl/mmcf
Most recent wells
March 2017
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OUTSTANDING WELL PERFORMANCE
16
13-21 IP 270 Average Production Rate 773 boe/d
Condensate yield of 164 bbl/mmcf sales
0
1,000
2,000
3,000
4,000
5,000114
5116
3525
99
74
26
5273057
Top Decile for 3-Month
Production Rates
IP90 (mcf/d)
527 Wells of 927 Wells Drilled
March 2017
Well Count Sales Production Rate
Gasmmcf/d
FieldCondensate
bbl/dTotal
boe/d
CondensateYield
bbl/mmcf
IP30 24 4.6 461 1,417 99
IP90 22 4.2 323 1,182 78
IP180 21 3.6 245 978 69
IP270 20 3.1 204 850 65
IP365 18 2.8 165 746 59
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DELPHI WELL COST IMPROVEMENTS
17
Delphi Well CostsDelphi Well Costs
IP90 Day Capital Efficiencies
Montney Capital Efficiencies
0
5,000
10,000
15,000
2012 2013 2014 2015 2016
90 Day D&C $ Efficiency ($/boe/d) 90 Day Comp $ Efficiency ($/boe/d)
Cap
ital
Eff
icie
ncy
($
/bo
e/d
)
$0
$100
$200
$300
$400
$500
$600
$0
$2,000
$4,000
$6,000
$8,000
$10,000
$12,000
2012 2013 2014 2015 2016
Drilling Costs Completion Costs Avg. Comp. $/Stage
Ave
rage
Co
sts
($0
00
)
Ave
rage C
om
ple
tion
Co
st/Stage ($
00
0)
Well costs ↓ 35%
Drilling & Completions:
Average drilling & completion costs per well
have trended down by 35%;
$11 million in 2012 to $7 million in most
recent five wells
Record low drilling & completions cost of
$6.5 million achieved
Additional cost savings are being achieved;
3 - 4 wells per pad from 2 well pads
IP90 Capital Efficiencies:
Top decile efficiencies of $6,000 boe/d
Achieved through cost reductions and
robust IP90 rates of 1,200 boe/d
March 2017
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MONTNEY ECONOMIC MODEL
18
Rich Type Well13-21 Yield 2.5x Type Well at 100 bbl/mmcf
Note: See Montney Economic Model Assumptions in the Forward Looking Statement and
Important Notes
DEE Type WellBigstone Montney Toe Up Two Section Horizontal
Hypothetical Type Wells30+ stage Slickwater Completion
Economics/Metrics - January 9, 2017 Strip
Pricing(1)
Type Well Rich Type Well
Payout yrs 1.2 1.1
IRR % 79% 108%
NPV 10 MM$ $6.9 $12.0
PI 2.0 2.7
F&D $/boe $6.42 $5.51
Target Capital
D,C,E&TI MM$ $7.0 $7.0
Initial Sales Production (IP30 - first 30 day
average)
Gas mmcf/d 5.1 3.6
Field Condensate(2) bbl/mmcf 98 185
Total Liquids (C3+)(2,3) bbl/mmcf 137 224
Total Liquids (C3+)(2,3) bbl/d 696 804
Total IP30 boe/d 1,542 1,402
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 3.9
Liquids (C3+)(2,3) mmbbl 0.4 0.6
Total mmboe 1.1 1.3
March 2017
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2017 DRILLING PLANS
Legend
Drilled
Drilling 2017
• 6 – 8 wells to be drilled in 1H 2017
• Approx. 5 to 6 wells funded under a joint program
• Remaining wells will be funded within cash flow
• Production growth weighted to 2H 2017
Largest drilling program yet
March 2017
Accelerating To The West
Two rigs active
Utilizing existing infrastructure
Positive frac design evolution
Significant inventory;
147 sections
Multiple layers
Montney thickness increasing;
6 laterals per section
Multiple layers to drill
Natural gas is sweet;
DEE sweet infrastructure
40 mmcf/d capacity
Lower operating costs
Condensate yields increasing
Reservoir pressure increasing
19
WEST EAST
19
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2017 AND BEYOND – MAINTAINING KEY VALUES
20
Continued new well innovation; significant infrastructure and processing
capacity in place
Substantial drilling inventory on 147 sections of land; 8 sections fully
developed, significant free cash generated at payout
World Class Montney Asset
Operational Control
Land Inventory
Market Access
Performance
Growth to 2019 will utilize existing major infrastructure, with minimal capital
required
No significant infrastructure capital required in this environment, low
operational costs
Operating efficiency gains lifting “unhedged” netbacks through 2019
2017 drilling program to double with a second rig
$20 million Partner carried drilling cost to accelerate growth
147 sections of Montney opportunity to continue developing
Partner has contributed $30 million in cash for working interest equalization
Secured firm service with Alliance to access Chicago gas market for
stronger pricing
NEB, FirstEnergy, EIA, USGS
March 2017
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APPENDIX
March 2017 21
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BIGSTONE MONTNEY OVERVIEW
22
Scalable and Repeatable
Liquids Rich
Large Resource in Place
Southeast corner of the unconventional Montney
trend
Developed with extended reach horizontal wells and
slickwater-fracing
Material capital cost advantage
Continuous hydrocarbon system top to bottom
Nearby deltaic sediment supply
Relatively high permeability with a fine sand/silt
reservoir
Relatively high porosity ranging from 4% to 12%
Thickness of 100 metres - increasing to the west
Multiple layers to develop
Field condensate yields at over 55 bbl/mmcf
Recent yields materially higher
Significant additional liquids extracted through gas
processing
Top decile gas rate wells with > 5 mmcf/d IP30’s
March 2017
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$50 MILLION PARTNER TRANSACTION OVERVIEW
23
$20 Million Joint Drilling Program
Delphi retains
operatorship of the
Bigstone Montney capital
program, production and
facilities.
$30 Million Cash Consideration
Delphi will contribute 15% of the drilling and completion costs ($6 million)
while retaining a 65% working interest in the wells;
Partner will carry the remaining 50% of Delphi’s share of the drilling and completion
costs, to a maximum of $20 million
The program contemplates 5 – 6 wells drilled before July 15, 2017
Delphi received $30 million in cash at closing as equalization consideration
Transaction Assets
The Partner increased working interests, to varying degrees, in partially developed and undeveloped lands,
production and infrastructure;
450 barrels of oil equivalent (“boe”) per day (approx. 5% of its productive capability)
Partner received a 35% working interest in Delphi’s 100% owned sour processing infrastructure
Delphi assigned various working interests in its land base at Bigstone Montney to the Partner;
Delphi holds 65% and the Partner holds 35% of the combined interests;
Delphi’s total developed, partially developed and undeveloped land position have changed from approx. 117 net sections
(138 gross) to 87 net sections (143 gross);
Delphi assigned a total of 25.4 net undeveloped sections to the Partner
Delphi received a total of 2.25 net undeveloped sections from the Partner
March 2017
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INDIVIDUAL MONTNEY WELL DATA
24March 2017
Number IP30 IP30 IP30 IP90 IP180 IP270 IP365 IP 2yr
HZ Length of Fracs Total Sales FCond Rate Total NGL Total Sales Total Sales Total Sales Total Sales Total Sales
Yield
(metres) (boe/d) (bbls/d) (bbl/mmcf) (boe/d) (boe/d) (boe/d) (boe/d) (boe/d)
16-30 #1 2,760 20 1,099 273 104 798 558 454 395
05-02 #2 3,005 20 969 170 80 683 479 407 352 253
14-23 #3 2,238 20 1,570 223 70 939 635 532 445 294
15-10 #4 1,424 20 991 194 86 842 660 559 482 330
12-17 S.BS Expl(3) 1,848 26 865 199 102 719 554 470 415 297
2,400 – 3,000 30+ 1,542 496 137 1,258 1,028 882 783 563
10-27 #5 2,407 30 1,815 582 133 1,667 1,364 1,173 1,019 688
16-23 #6 2,809 30 1,781 465 108 1,502 1,235 1,068 964 708
15-24 #7 2,328 30 1,387 454 136 1,221 1,059 944 853 615
15-30 #8 3,014 30 2,076 566 113 1,837 1,517 1,324 1,164 795
15-21 #9 2,886 30 1,293 499 170 1,053 875 769 689 491
13-30 #10 2,593 30 2,075 655 136 1,750 1,457 1,268 1,119 732
02-01 #11 2,807 30 634 209 142 498 422 367 329 254
02-07 #12 2,702 30 1,116 327 126 940 750 647 570 413
08-21 #13 2,692 30 978 280 123 870 712 607 529
16-15 #14 2,949 30 1,503 298 91 1,217 1,017 861 749 496
03-26 #15 2,601 30 1,053 330 134 755 592 506 447 318
13-23 #16 2,161 30 1,556 400 111 1,282 966 820 717 479
16-27 #17 2,883 40 1,659 413 108 1,296 1,045 890 761 546
12-27 #18 2,662 30 1,670 593 154 1,337 1,102 935 818
16-24 #19 2,802 40 1,182 410 150 929 757 655 586
13-24 #20 2,716 40 1,526 469 132 1,172 948 821 728
14-30 #21 2,729 37 1,840 505 118 1,407 1,112 950 805
14-24(4) #22 2,602 37 1,119 435 172 976 792 677 585
14-27(4) #23 2,887 37 1,414 572 180 1,280 1,082 939
13-21(4) #24 2,781 37 1,204 662 291 1,077 962 773
15-23 #25 2,865 37 1,153 359 133 909 779
14-11 #26 2,846 42 1,212 412 146 1,028
16-09 #27 2,855 40 1,161 421 167
14-21 #28 2,788 40 1,606 737 226
16-21 #29 2,858 40 1,968 763 180
15-8 #30 2,740 completed and waiting on IP30
15-11 #31 2,866 waiting on completion
13-15 #32 2,891 completed and waiting on IP30
15-09 #33 2,864 waiting on completion
1,439 473 147 1,182 978 850 746 545
Conventional Fracs (original completion technique)
Slickwater Fracs (new completion technique)
Average Wells #5 through #28
Well(2)
Initial Production (IP) Rate Well Performance (1)
Type Well
(2) Wells numbered chronologically.
(3) Initial exploration w ell on Delphi's South Bigstone lands.
(4) Initial production restricted to tubing f low only.
(1) Average production calculated on operating days, excludes non-producing days. Includes estimated NGL gas plant recoveries. All production numbers represent sales volumes.
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COMMODITY PRICES: MANAGING VOLATILITY
25
Volatility creates
hedging
opportunities
CDN/US FX
NYMEX Contract Pricing
GA
S U
S$
/MM
BT
U
CR
UD
E U
S$
/BB
L
Natural gas prices were historically correlated to Crude prices
NYMEX NatGas vs. Crude Historical Settlement Pricing
Commodity price volatility creates 2
to 4 year hedging cycles
March 2017
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HEDGES PROTECTING CASH FLOW
26
Natural Gas (Cdn) Apr – Dec 2017Volume (mmcf/d) 2.4% Hedged (1) 7%Hedge Price (Cdn $/mcf) (2) $3.96Strip Price (Cdn $/mcf) $2.78
Natural Gas (US) Apr – Dec 2017 2018 2019Volume (mmbtu/d) 19.5 15.5 7.0% Hedged (1) 58% 46% 21%Hedge Price (US $/mmbtu) $3.18 $2.94 $2.92Strip Price (US $/mmbtu) $3.21 $3.06 $2.88% Hedged in Cdn $ (3) 100% 100% 100%Hedge Price (Cdn $/mmbtu) (4) $4.23 $3.88 $3.89
Crude Oil Apr – Dec 2017 2018 2019Volume (bbls/d) 900 300 300% Hedged (1) 42% 14% 14%Hedge Price (WTI Cdn $/bbl) $66.67 $70.00 $70.00Strip Price (WTI Cdn $/bbl) $67.21 $67.33 $66.63
(1) Based on average 2017 production of approximately 33.5 mmcf/d of natural gas and 2,150 bbls/d of field condensate(2) Before deduction of transportation costs to ship production to AECO on the TCPL pipeline(3) Percent of US $ hedge value locked in with Cdn/US FX hedges(4) Before deduction of transportation costs to ship production to Chicago on the Alliance pipeline(5) Strip pricing as of March 10, 2017
March 2017
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LIQUIDS-RICH MONTNEY STUDY
ELMWORTH TO BIGSTONE
27
Elmworth
Wapiti
Kakwa
Delphi
Bigstone
Large Data Set
527 Montney wells with IP90 of
937 wells drilled to YE2016
Source of Data: geoSCOUT
27
Company 6
Company 7
Delphi
Company 3
Company 4
Company 1
Company 2
Company 8
Company 5
Other
March 2017
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28
0
20
40
60
80
100
120
140
160
180
200
2008 2009 2010 2011 2012 2013 2014 2015
Producing Wells by Rig Release DateTotal Wells (with IP90): 527
*produced for at least 90 days
0
20
40
60
80
100
120
Producing Wells by Operator
28
LIQUIDS-RICH MONTNEY STUDY
ELMWORTH TO BIGSTONE
March 2017
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LIQUIDS-RICH MONTNEY STUDY
PRODUCTION BY OPERATOR (GAS IP’S ONLY)
29
0
1,000
2,000
3,000
4,000
5,000
IP90 (mcfd raw)527 wells
0
1,000
2,000
3,000
4,000
5,000
IP180 (mcfd raw)418 wells
0
1,000
2,000
3,000
4,000
5,000
IP365 (mcfd raw)288 wells
29March 2017
16 51 25 114 35 30 57 99 74 26 527 15 76 21 41 56 30 31 77 47 24 418
15 44 29 50 20 24 26 34 29 17 288
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0
500
1,000
1,500
2,000
2,500
3,000
Average Horizontal Length (m)
LIQUIDS-RICH MONTNEY STUDY
EVOLUTION OF DEPTH & HORIZONTAL LENGTH
30
2,000
2,500
3,000
3,500
4,000
4,500
5,000
5,500
6,000
2008 2009 2010 2011 2012 2013 2014 2015
Average Measured Depth (m)
920 42
61
0
500
1,000
1,500
2,000
2,500
3,000
2008 2009 2010 2011 2012 2013 2014 2015
Average Horizontal Length (m)
Delphi AvgDelphi Avg
0
1,000
2,000
3,000
4,000
5,000
6,000
Average Measured Depth (m)
114 25 30 35 51 26 74 57 99 16 527
2
101177
61
101177
61
61
920 42
2
30March 2017
25 114 57 30 26 51 35 74 99 16 527
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0
5
10
15
20
25
30
2008 2009 2010 2011 2012 2013 2014 2015
Average Number of Stages per Well
LIQUIDS-RICH MONTNEY STUDY
EVOLUTION OF FRAC DENSITY
31
0
20
40
60
80
100
120
140
160
180
200
2008 2009 2010 2011 2012 2013 2014 2015
Average Frac Spacing (m)
Delphi Avg (97m)
2
9
19 40
60
100
176
592
6
16
39
51
166 5085
Delphi Avg (29 stages)
31
0
5
10
15
20
25
30
35
Average Number of Stages per Well
0
20
40
60
80
100
120
140
Average Frac Spacing (m)
March 2017
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32
0
20
40
60
80
100
120
140
160
180
200
0 - 10 11 - 15 16 - 20 21 - 25 26 - 30 31 - 35 36 - 40
Number of Wells
0
1,000
2,000
3,000
4,000
5,000
0 - 10 11 - 15 16 - 20 21 - 25 26 - 30 31 - 35 36+
IP90 (mcfd raw)465 wells
0
1,000
2,000
3,000
4,000
5,000
0 - 10 11 - 15 16 - 20 21 - 25 26 - 30 31 - 35 36 - 40
IP180 (mcfd raw)411 wells
0
1,000
2,000
3,000
4,000
5,000
0 - 10 11 - 15 16 - 20 21 - 25 26 - 30 31 - 35 36 - 40
IP365 (mcfd raw)285 wells
Stages per WellStages per Well
Stages per Well Stages per Well
18
80
149 9079
21
28
16
76133 75
70 20 21
12
66
93 48 4711
8
32
LIQUIDS-RICH MONTNEY STUDY
EVOLUTION OF FRAC DENSITY
March 2017
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LIQUIDS-RICH MONTNEY STUDY
EVOLUTION OF PROPPANT PLACED
33
0
1,000
2,000
3,000
4,000
5,000
6,000
0.00
0.20
0.40
0.60
0.80
1.00
1.20
1.40
2008 2009 2010 2011 2012 2013 2014 2015
Proppant Placed
tonnes t/m
0
1,000
2,000
3,000
4,000
5,000
0.00 - 0.25 0.26 - 0.50 0.51 - 0.75 0.76 - 1.00 1.01 - 1.25 1.26 - 1.50 1.51 +
IP-90 (mcfd raw)
t/m
0
1,000
2,000
3,000
4,000
5,000
0.00 - 0.25 0.26 - 0.50 0.51 - 0.75 0.76 - 1.00 1.01 - 1.25 1.26 - 1.50 1.51 +
IP-180 (mcfd raw)
t/m
25
43
74128
77 6052
25
38
119
70
68
51 34
2 8 19 42 61 100 175 59
Delphi Avg (0.76 t/m)
33March 2017
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LIQUIDS-RICH MONTNEY STUDY
EVOLUTION OF FLUID PUMPED
34
0
2,000
4,000
6,000
8,000
10,000
12,000
14,000
16,000
18,000
20,000
0.00
1.00
2.00
3.00
4.00
5.00
2008 2009 2010 2011 2012 2013 2014 2015
Fluid Pumped
m3/well m3/m
0
1,000
2,000
3,000
4,000
5,000
0.0 - 2.0 2.1 - 4.0 4.1 - 6.0 6.1 - 8.0 8.0+
IP-90 (mcfd raw)
0
1,000
2,000
3,000
4,000
5,000
0.0 - 2.0 2.1 - 4.0 4.1 - 6.0 6.1 - 8.0 8.0+
IP-180 (mcfd raw)
m3/m m3/m
110
19364
5445
107
163 57 49 36
2 8 19 42 61 100 175 59
Delphi Avg (3.65 m3/m)
34March 2017
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LIQUIDS-RICH MONTNEY STUDY
FRAC TYPES
35
228
176
107
45
0
50
100
150
200
250
Frac by Fluid Type
35
0
1,000
2,000
3,000
4,000
5,000
IP-90 IP-180 IP-1YR IP-2YR IP-3YR
Frac by Fluid Type(mcfd raw)
slickwater water oil surfactant
March 2017
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36
0
10
20
30
40
50
60
Average Drilling Days
57 17 31 21 25 94 47 61 19 89 36 497
36
LIQUIDS-RICH MONTNEY STUDY
DRILLING EFFICIENCY
0
500
1,000
1,500
2,000
2,500
3,000
Average Horizontal Length (m)
0
50
100
150
200
250
2008 2009 2010 2011 2012 2013 2014 2015
Average Penetration Rate (m/d)
Delphi Avg
Only 2 wells in 2008 dataset (both with
horizontal lateral lengths less than 800m)
Over a 6 year period, industry improved
overall drilling penetration rates by
almost 50%. The faster a well can be
drilled, the less it costs.
March 2017
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