CORPORATE STRATEGY
PRESENTATION
SEPTEMBER 2016
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% per year thereafter. 2017 prices: Henry Hub $3.13/mmbtu US,
$4.09/mmbtu CDN; WTI $48.82/bbl USD; C5 $64.02/bbl CDN. 2018 Prices: Henry Hub $2.99/mmbtu US, $3.90/mmbtu CDN; WTI $50.93/bbl USD; C5 $66.22/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.Alberta Modernized Royalty Framework for wells drilled after January 1, 2017. 5. 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. 6. 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 (July 2016) of 82
bbl/mmcf sales. The recent 103/13-21-60-23W5 well was restricted to flow up the tubing only and produced 2.6 mmcf/d sales of natural gas and 662 bbl/d of field condensate over it's first 30 days of production. Reserve
estimates include estimated gas plant recovered natural gas liquids of 40 bbl/mmcf sales. 7. Reserve and production estimates are used for illustrative purposes and internal corporate planning and may not reflect the 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.
September 2016
CORPORATE SNAPSHOT
KEY OPERATIONAL FIGURES
July 2016 Production boe/d 8,500 (64% gas)
Dec. 31, 2015 Reserves (P+P) (mmboe) 45.5 (67% gas)
Current Production Capability 9,000 – 9,300 boe/d
2016 GUIDANCE
Average Annual Production (boe/d) 7,700 – 8,000
Exit Production Rate (boe/d) 9,000 – 10,000
2015 Production Rate Exit (boe/d) 8,300
NYMEX Natural Gas Price (US $ per mmbtu) $2.35 - $2.55
WTI Oil Price (US $ per bbl) $40.00 - $43.00
Natural Gas Liquids Price (Cdn $ per bbl) $17.00 - $19.00
Foreign Exchange Rate (US/Cdn) 1.30 – 1.35
Well Count 4.0 – 5.0
Net Capital Program ($ million) $33.0 - $38.0
Funds from Operations (“FFO”) ($ million) $31.0 - $34.0
(1) As of June 2016. Bank debt includes working capital and $6.0 million of Letters of Credit
Grande Prairie
Bigstone
Montney
Edmonton
Calgary
September 2016 3
CORPORATE INFORMATION
Ticker Symbol TSX:DEE
Basic Shares Outstanding (mm) 155.5
Market Capitalization (mm) $160.0
Bank Debt (1) / Credit Facility (mm) $71.7 / $85.0
5 Year Senior Secured Notes (mm) $60.0
KEY VALUE HIGHLIGHTS
Pure Play Montney E&P Company with WORLD CLASS ASSETS AND A TRACK RECORD OF SUCCESS
Substantial drilling inventory on 139 sections of land; 8 sections currently fully developed
Bigstone Montney economics remain attractive in the current commodity price environment
Free cash generated at payout remains significant
Targeting growth to 22,000 boe/d in 2019 utilizing existing major infrastructure, increase of 160%
100% owned and operated field facilities and pipelines to support profitable growth
Operate 100% of Montney development with an average working interest of 84%
Drilling and completion costs down 33 percent and operating costs down 30%, since 2014
Secured firm service with Alliance to access Chicago gas market for better pricing and fewer curtailments
Significant hedged position in place through 2019
Added $95 million in cash as a result of an exceptional hedging program
Reduced debt by 30% from the sale of non-core assets – now 100% focused at Bigstone
Achieving targets within cash flow to accelerate 2017 growth with increased liquidity
Replacing PDP reserves with higher netback boe’s than depleting – turning $1 spent into $2 returns
Moderating short-term pace of spend while preserving long-term growth inventory
Exceptional management team with a track record of value creation
Frac innovations and increased condensate yields leading to better margins
Top tier well results and capital efficiencies – 2 mile extended reach drilling improving overall well results
Delivering top quartile PDP F&D costs and recycle ratios
WORLD CLASS
MONTNEY GROWTH
ASSET
100% OPERATIONAL
CONTROL
MARKET ACCESS &
EXCEPTIONAL RISK
MANAGEMENT
RESPONSIBLY
MANAGED
PROFITABLE GROWTH
EXECUTIONAL
EXCELLENCE
September 2016 4
BIGSTONE MONTNEY OVERVIEW
5
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%
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
Thickness of 100 metres - increasing to the west
Multiple layers to develop
Porous and Permeable
September 2016
Edmonton
Bigstone
Montney
Grande Prairie
6
0
50
100
150
200
2008 2009 2010 2011 2012 2013 2014 2015
Producing* Wells by Rig Release DateTotal Wells: 724
Delphi maintains a
100% success rate
0
20
40
60
80
100
Company1
Company2
Other Company3
Company4
Company5
Company6
Company7
Delphi Company8
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
September 2016
* 473 Wells with IP90 or greater
Elmworth
DOMINANT LAND POSITION IN BIGSTONE MONTNEY
Legend
Delphi continues to identify and
pursue additional land
consolidation opportunities
within the Greater Bigstone area
Largest Land Position at Bigstone
Bigstone Activity by Region
East Bigstone – manufacturing / development
West Bigstone – industry activity derisking
South Bigstone – exploration opportunity
There is presence of and development activity
by super-majors; Exxon, Chevron, and
ConocoPhillips operate in the general area
Montney land position grown from 4.0 to 139
gross (117.1 net) sections since 2010
Delphi is currently the largest landowner at
Bigstone
Significant land position allows for efficient
operations, control over infrastructure and
scalable development
8 sections currently fully developed with
substantial room to grow through drilling
Drilling program moving west into ultra-rich
condensate region
September 2016 7
WEST BIGSTONE
SOUTH BIGSTONE
EAST BIGSTONE
Other
Rge25W5 Rge24
STRATEGIC INFRASTRUCTURE AT BIGSTONE
Significant Infrastructure In Place
100% owned 55 mmcf/d sour dehy
and compression facilities
Legacy sour processing capacity
available at SemCAMS K3 and KA
Connected to Pembina, TCPL and
Alliance
Ownership of 40 mmcf/d sweet
processing infrastructure
100% owned water disposal well
operational in Q4 2015
Ability to grow to 22,000 boe/d utilizing
current major infrastructure
$4.00
$5.00
$6.00
$7.00
$8.00
$9.00
$10.00
$11.00
$12.00
2012 2013 2014 2015 2016E
Op
era
tin
g C
os
ts (
$/b
oe
)Montney Operating Costs
Operating cost decrease by 30% since 2014
to $5.87/boe in Q2/16
September 2016 8
DEE 7-11
55 mmcf/d
Montney Facility
To SemCAMS
Future DEE Amine Plant
To TCPL
TLM BWGP85 mmcf/d Plant
DEE Negus 11-03
Gas Plant
DEE 5-810 mmcf/d
Montney Facility
MARKET ACCESS ADVANTAGE
9
Exceptional Gas Marketing
Secured firm service agreement to access larger Chicago gas market for better pricing
Pricing has been significantly better that AECO
Secured firm service minimizing exposure to curtailments on the TCPL pipeline system
Ability to grow to 22,000 boe/d over the next 3 years utilizing current major infrastructure
September 2016
Delphi / Alliance
Full-path service to Chicago
DELPHI / ALLIANCE FIRM TRANSPORTATION SERVICE
10
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)
TCPL Firm Alliance Firm
July 2016 Average Natural Gas
Production
Staged firm service capacity on Alliance to deliver
natural gas to the Chicago gas market with priority
interruptible service allocation of an additional 25%
capacity. Renewal rights on firm service included in
agreement.
Incremental firm service on TCPL beginning April
2018 as part of TCPL expansion. Renewal rights on
firm service included in agreement.
September 2016
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 to 4 year “peak to trough”
event cycles
Risk management contracts generally
put in place over a 12 to 48 month
period
Over a 10 year period risk management
program has:
Realized $95 million in hedging
gains
Increased revenues by 8%
Increased cash flow by 18%
Added $3.35/boe to netback -$15
-$10
-$5
$0
$5
$10
$15
$20
$25
$30
$35
Hedging Gains/Losses ($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 both natural gas
and crude oil prices
Consistent Hedge Performance Natural Gas 2H/16 Q1/17 Q2 - Q4/17 2018 2019
% Hedged 78% 73% 59% 30% 21%
Hedge Price (Cdn $/mmbtu) $4.44 $4.28 $4.21 $3.77 $3.89
Crude Oil 2H/16 Q1/17 Q2 - Q4/17 2018 2019
% Hedged 49% 16% 16%
Floor Price (WTI Cdn $/bbl) $76.44 $60.00 $60.00
Ceiling Price (WTI Cdn $/bbl) $85.00 $60.00 $60.00
September 2016 11
28 BIGSTONE MONTNEY WELLS DRILLED
12
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 20 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
Drilling 4 to 5 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 139 sections for 2017 and beyond with high condensate yields
Progressive improvements in Drilling Results
September 2016
Legend
2012-2015 (24 wells)
2016 (4 to 5 wells)
DEE 7-11 Sour Facility
Expanded to 55 mmcf/d in
Q1 2016
DEE 5-8 Sour Facility
10 mmcf/d
MONTNEY GROWTH AT BIGSTONE
Bigstone Montney Liquids-Rich Gas Play Montney Production
0
2,000
4,000
6,000
8,000
10,000
2012 2013 2014 2015 2016 (Exit)
Growth is
accelerating into
2017
0
500
1,000
1,500
2,000
2012 2013 2014 2015 2016 (Exit)
Montney condensate production is accelerating with increasing yields
Montney Field Condensate Production
September 2016 13
2012 2013 2014 2015 2016(F) 2017Target
68
65
4-5
Delphi Montney Wells Drilled
7-10
Southeast corner of Alberta liquids-rich Montney
trend, 100 – 300 bbl/mmcf Condensate & NGL
28 wells drilled life-to-date in the Montney from
2012 to Q2 2016
139 gross sections of Montney rights (84%
average working interest)
Thickness of 100m - increasing to the west
Better than average rock quality – higher
Permeability & Porosity , normal to overpressured
reservoirs
CONSISTENT ECONOMIC RESERVE GROWTH
14
2012 2013 2014 2015
43,434
50,728
33,100
11,0063 year full-cycle 2P FDA of $10.62/boe
LTD netback of $19.65/boe
30 undeveloped locations
2012 2013 2014 2015
11,626
9,781
4,370
1,178
Economic Montney reserve
growth with 2015 PDP FDA
of $10.12/boe
Montney Proved Producing Reserves (mboe)
Montney 2P Reserves (mboe)
September 2016
28 wells drilled life-to-date (LTD)
Produced 7.2 million boes in 4.5 years
Generated $127 million in field operating
income
Cumulative capital of $312 million
Including $40 million of infrastructure
costs
Significant Inventory for growth
Montney Development (2012 to Q2 2016)
2015 drilling program was focused on infill
locations;
19% PDP reserve growth
8 of 139 sections are fully developed
Only 30 undeveloped locations in 2P
reserves
2016 drilling program focused on moving
west
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
September 2016 15
8093
132 140 140
250
-
50
100
150
200
250
300
TypeWell
15-23 14-24 14-27 16-30*Refrac
13-21
Fie
ld C
on
de
ns
ate
Yie
ld (
bb
ls/m
cf)
*Not at IP30 yet
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 80
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
IP7 day
CGR 140 bbl/mmcf
Most recent wells
OUTSTANDING WELL PERFORMANCE
16September 2016
Well Count Sales Production RateGas Field Total Condensate
Condensate Yieldmmcf/d bbl/d boe/d bbl/mmcf
IP30 20 4.8 456 1,444 95IP90 20 4.2 331 1,203 79IP180 18 3.6 236 984 65IP270 16 3.2 195 853 61IP365 14 2.9 168 766 58
0
1,000
2,000
3,000
4,000
5,000
IP90 (mcfd raw)473 wells of 724 wells drilled
884816
33
20
94
59
26
47330 57
At day 158 13-21 gas rate flat at 3mmcf/d
Condensate yield at 115 bbl/mmcf sales
DELPHI WELL COST IMPROVEMENTS
17
Delphi Well CostsMontney Capital Efficiencies
September 2016
Delphi Well Costs
IP90 Day Capital Efficiencies
Montney Capital Efficiencies
0
5,000
10,000
15,000
2012 2013 2014 2015 2016 YTD
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 YTD
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 three 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
100% owned water disposal facility
IP90 Capital Efficiencies:
Top decile efficiencies of $6,000 boe/d.
Achieved through cost reductions and
robust IP90 rates of 1,200 boe/d.
Bigstone Montney Toe Up Two Section Horizontal Hypothetical
Type Wells
30+ stage Slickwater Completion
Economics/Metrics - August 31, 2016 Strip Pricing(1)
Type Well Rich Type Well
Payout yrs 1.6 1.3
IRR % 56% 81%
NPV 10 MM$ $5.6 $10.2
PI 1.8 2.5
F&D $/boe $6.42 $5.51
Target Capital Type Well Rich Type Well
D,C,E&TI MM$ $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
MONTNEY ECONOMIC MODEL
18September 2016
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 Well
DRILLING PLANS MOVING WEST
19
Montney pay thickness
increasing;
6 laterals per section
spacing
Multi-layer drilling
Natural gas is sweet;
DEE sweet infrastructure
40 mmcf/d capacity
Lower Operating Costs
Condensate and NGL yields;
2x to 4x greater than
East Bigstone type curve
Slickwater “frac design”
Reservoir pressure increases
Significant drilling opportunity
over 139 sections
Bigstone West
September 2016
DEE 9-4 Well
Conventional
Gelled Oil Frac in
2012
DEE activity planned for 2H
2016 and 2017
25 – 30 well inventory just in
this small area
Legend
Drilled
Drilling 2017
WEST EAST
DEE 13-21 Well
IP90 1,077 boe/d
CGR 194 bbl/ mmcf condensate
19
0
1,000
2,000
3,000
4,000
5,000 884816
33
20
94
59
26
47330
57
2017 AND BEYOND – MAINTAINING KEY VALUES
20
Continued new well innovation; Significant infrastructure
and processing capacity in place
World Class Montney Asset
100% Operational Control
Land Inventory
Market Access
Performance
Targeting growth to 22,000 boe/d in 2019 utilizing existing
major infrastructure, increase of 160%
No significant infrastructure capital required in this
environment, low operational costs
Operating efficiency gains lifting “unhedged” netbacks
through 2017
139 sections of Montney opportunity to continue developing
Top Decile for 3-Month
Production Rates
IP90 (mcf/d)
473 Wells of 724 Wells Drilled
Secured firm service with Alliance to access Chicago gas
market for better pricing
September 2016
APPENDIX
INDIVIDUAL MONTNEY WELL DATA
22
• Very strong long term performance• Even with payouts stretched to 1.9 years
from 1.0 years previously:• 250 - 350 boe/d• Significant free cash flow
Slow-back experiment
September 2016
COMMODITY PRICES: MANAGING VOLATILITY
23
Volatility creates
hedging
opportunities
September 2016
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
HEDGES PROTECTING CASH FLOW
24
Natural Gas (Cdn) Jul – Dec 2016 Jan – Mar 2017 Apr – Dec 2017Volume (mmcf/d) 2.4 2.4 2.4% Hedged (1) 7% 7% 7%Hedge Price (Cdn $/mcf) (2) $3.89 $3.96 $3.96Strip Price (Cdn $/mcf) $2.68 $2.98 $2.75
Natural Gas (US) Jul – Dec 2016 Jan – Mar 2017 Apr – Dec 2017 2018 2019Volume (mmbtu/d) 23.3 21.8 17.0 10.0 7.0% Hedged (1) 71% 66% 52% 30% 21%Hedge Price (US $/mmbtu) $3.50 $3.24 $3.20 $2.87 $2.92Strip Price (US $/mmbtu) $2.96 $3.25 $3.04 $2.97 $2.94% Hedged in Cdn $ (3) 100% 100% 100% 100% 100%Hedge Price (Cdn $/mmbtu) (4) $4.50 $4.31 $4.24 $3.77 $3.89
Crude Oil Jul – Dec 2016 Jan – Mar 2017 Apr – Dec 2017Volume (bbls/d) 900 300 300% Hedged (1) 49% 16% 16%Floor Price (WTI Cdn $/bbl) $76.44 $60.00 $60.00Ceiling Price (WTI Cdn $/bbl) (5) $85.00 $60.00 $60.00Strip Price (WTI Cdn $/bbl) $63.42 $65.59 $67.45
(1) Percent hedged is based on expected 2H 2016 average natural gas production of approximately 33 mmcf/d and 1,850 bbls/d of condensate and C5+.(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) 400 bbls/d have upside to a ceiling price of $85.00 per barrel at a deferred cost of $4.02 per barrel
September 2016
YIELD GROWTH REPLACES HEDGING GAINS IN 2017
25
$10.00
$15.00
$20.00
$25.00
$30.00
$35.00
$40.00
$45.00
0 50 100 150 200 250 300
Re
ven
ue
($
/bo
e)
Field Condensate Yield (bbl/mmcf sales)
15-30Life-to-Date
14-27IP30
Type Well
15-21Life-to-Date
Recycle Ratio = 1.5
2017 Strip PriceAECO Nat Gas: Cdn$2.47/mcfNYMEX Nat Gas: US$2.50/mmbtuWTI: US$45.00/bblCondensate: Cdn$54.50/bblNGLs: Cdn$16.50/bbl
13-21IP30
Recycle Ratio = 2.3
14-24IP30
$12.00/boe increase in revenue
(before hedges)
$2.10/boehedging gain
forecast in 2017
2016
2016
2017 drilling program will
continue to generate robust
new well revenue and netbacks
even with less hedging than
2016
New richer wells generate up to
a 2.3 PDP recycle ratio in 2017
on unhedged netbacks
PDP F&D of $10.00/boe
Cash costs of 16.00/boe
September 2016
LIQUIDS-RICH MONTNEY STUDY
ELMWORTH TO BIGSTONE
26
Elmworth
Wapiti
Kakwa
Delphi
Bigstone
Large Data Set
473 Montney wells with IP90 of
724 wells drilled to YE2015
Source of Data: geoSCOUT
26September 2016
Company 6
Company 7
Delphi
Company 3
Company 4
Company 1
Company 2
Company 8
Company 5
Other
27
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): 473
*produced for at least 90 days
0
20
40
60
80
100
Company1
Company2
Other Company3
Company4
Company5
Company6
Company7
Delphi Company8
Producing Wells by Operator
27September 2016
LIQUIDS-RICH MONTNEY STUDY
ELMWORTH TO BIGSTONE
LIQUIDS-RICH MONTNEY STUDY
PRODUCTION BY OPERATOR (GAS IP’S ONLY)
28
0
1,000
2,000
3,000
4,000
5,000
IP90 (mcfd raw)473 wells
884816 3322 94 59 26 47330 570
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
21 4115 5676 77 47 24 41830 31
15 2050 2444 29 34 29 17 28826
28September 2016
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
29
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)
2
101177
61
101177
61
61
920 42
2
88 22 30 33 48 26 57 59 94 16 473 8822 30 33482657 59 94 16 473
29September 2016
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
30
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)
30September 2016
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)
31
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
80149 90
7921
28
16
76133 75
70 20 21
12
66
93 48 4711
8
31September 2016
LIQUIDS-RICH MONTNEY STUDY
EVOLUTION OF FRAC DENSITY
LIQUIDS-RICH MONTNEY STUDY
EVOLUTION OF PROPPANT PLACED
32
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)
32September 2016
LIQUIDS-RICH MONTNEY STUDY
EVOLUTION OF FLUID PUMPED
33
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)
33September 2016
LIQUIDS-RICH MONTNEY STUDY
FRAC TYPES
34
228
176
107
45
0
50
100
150
200
250
Fracs by Fluid Type
34September 2016
0
500
1,000
1,500
2,000
2,500
3,000
3,500
4,000
4,500
5,000
IP-90 IP-180 IP-1YR IP-2YR IP-3YR
Fracs by Fluid Type(mcfd raw)
slickwater water oil surfactant
35
0
10
20
30
40
50
60
Average Drilling Days
57 17 31 21 25 94 47 61 19 89 36 497
35September 2016
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.
300, 500 – 4th Avenue SW
Calgary, Alberta T2P 2V6
P (403) 265-6171
F (403) 265-6207
www.delphienergy.ca