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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


ELMWORTH TO BIGSTONE


PRODUCTION BY OPERATOR (GAS IP’S ONLY)

28

0

1,000

2,000

3,000

4,000

5,000


884816 3322 94 59 26 47330 570

1,000

2,000

3,000

4,000

5,000


0

1,000

2,000

3,000

4,000

5,000


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)


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


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+


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


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


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


EVOLUTION OF FRAC DENSITY


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


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


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


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

[email protected]

www.delphienergy.ca

mailto:[email protected]

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