CORPORATE

PRESENTATION

ANNUAL GENERAL MEETING OF SHAREHOLDERS

MAY 24, 2016

FORWARD-LOOKING STATEMENTS

May 24, 2016 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 future performance and are based upon the Company’s internal assumptions and expectations. All statements other than statements of present or historical fact are

forward-looking statements. Forward-looking statements are often, but not always, identified by the use of any of the words “expect”, “anticipate”, “continue”, “estimate”, “may”, “will”,

“should”, “believe”, "intends”, “forecast”, “plans”, “guidance”, “budget” and similar expressions. More particularly and without limitation, this presentation contains forward-looking statements

and information relating to petroleum and natural gas production estimates and weighting, projected crude 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 capital expenditures and net debt,

planned capital spending, future liquidity and Delphi’s ability to fund ongoing capital requirements through operating cash flows and its credit facilities, supply and demand fundamentals for

oil and gas commodities, timing and success of development and exploitation activities, cash availability for the financing of capital expenditures, access to third-party infrastructure,

treatment under governmental regulatory regimes and tax laws and future environmental regulations. Furthermore, statements relating to “reserves” are deemed to be forward-looking

statements as they involve the implied assessment, based on certain estimates and assumptions that the reserves described can be profitable in the future. The forward-looking statements

and information contained in this presentation are based on certain key expectations and assumptions made by Delphi. The following are certain material assumptions on which the

forward-looking statements and information contained in this presentation are based: the stability of the global and national economic environment, the stability of and commercial

acceptability of tax, royalty and regulatory regimes applicable to Delphi, exploitation and development activities being consistent with management’s expectations, production levels of Delphi

being consistent with management’s expectations, the absence of significant project delays, the stability of oil and gas prices, the absence of significant fluctuations in foreign exchange

rates and interest rates, the stability of costs of oil and gas development and production in Western Canada, including operating costs, the timing and size of development plans and capital

expenditures, availability of third party infrastructure for transportation, processing or marketing of oil and natural gas volumes, prices and availability of oilfield services and equipment being

consistent with management’s expectations, the availability of, and competition for, among other things, pipeline capacity, skilled personnel and drilling and related services and equipment,

results of development and exploitation activities that are consistent with management’s expectations, weather affecting Delphi’s ability to develop and produce as expected, contracted

parties providing goods and services on the agreed timeframes, Delphi’s ability to manage environmental risks and hazards and the cost of complying with environmental regulations, the

accuracy of operating cost estimates, the accurate estimation of oil and gas reserves, future exploitation, development and production results and Delphi’s ability to market oil and natural

gas successfully to current and new customers. Additionally, estimates as to expected average annual production rates assume that no unexpected outages occur in the infrastructure that

the Company relies on to produce its wells, that existing wells continue to meet production expectations and any future wells scheduled to come on in the coming year meet timing and

production expectations. Commodity prices used in the determination of forecast revenues are based upon general economic conditions, commodity supply and demand forecasts and

publicly available price forecasts. The Company continually monitors its forecast assumptions to ensure the stakeholders are informed of material variances from previously communicated

expectations. Financial outlook information contained in this presentation about prospective results of operations, financial position 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 expectations

reflected in such forward-looking statements and information are reasonable, it can give no assurance that such expectations will prove to be correct and such forward-looking statements

should not be unduly relied upon. Since forward-looking statements and information address future events and conditions, by their very nature they involve inherent known and unknown

risks and uncertainties. Delphi’s actual results, performance or achievements could differ materially from those expressed in, or implied by, these forward-looking statements and,

accordingly, no assurance can be given that any of the events anticipated by the forward-looking statements will transpire or occur, or if any of them do so, what benefits Delphi will derive

therefrom. Should one or more of these risks or uncertainties materialize, or should assumptions underlying forward-looking statements prove incorrect, actual results may vary materially

from those currently anticipated due to a number of factors and risks. These include, but are not limited to, the risks associated with the oil and gas industry in general such as 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 and

projections relating to production rates, costs and expenses, commodity price and exchange rate fluctuations, marketing and transportation, environmental risks, competition from others for

scarce resources, the ability to access sufficient capital from internal and external sources, changes in governmental regulation of the oil and gas industry and changes in tax, royalty and

environmental legislation. Additional information on these and other factors that could affect the Company’s operations or financial results are included in the Company’s most recent

Annual Information Form and other reports on file with the applicable securities regulatory authorities and may be accessed through the SEDAR website (www.sedar.com). Readers are

cautioned that the foregoing list of factors is not exhaustive. Furthermore, the forward-looking statements contained in this presentation are made as of the date of this presentation for the

purpose of providing the readers with the Company’s expectations for the coming year. The forward-looking statements and information may not be appropriate for other purposes. Delphi

undertakes no obligation to update publicly or revise any forward-looking statements or information, whether as a result of new information, future events or otherwise, unless so required by

applicable securities laws. The forward-looking statements contained in this presentation are expressly qualified in their entirety by this cautionary statement.

A MONTNEY FOCUSED BUSINESS MODEL

May 24, 2016 3

• Delphi’s Bigstone Montney remains a Top Tier growth asset

• Maintains favorable economics in the current commodity price environment

• Free cash generated at payout remains significant

• Significant drilling inventory on 139 sections of land

• Ownership of infrastructure provides a cost advantage

• Expanding throughput capacity as required

• Driving operating and transportation costs lower

• Operating costs down 19 percent in Q1 2016

• 100 percent owned water disposal well

• New fuel gas source with additional compression

• Condensate trucking cost reduction/optimization

• Frac innovations and production cost reductions leading to better margins

• Drilling and completion costs down 33 percent since 2014

• Delivering top quartile PDP F&D costs and recycle ratios

A DIRECTIONAL LOOK AT 2016

May 24, 2016 4

2016 Priorities Through This Structural Reset

• Maintain financial flexibility• Capex in the context of cash flow• Reduced debt by 30 percent with Wapiti and Hythe dispositions in 2015• Significant hedge position for 2016 and 2017 volumes

• 75% of natural gas and 56% of field and plant condensate• 95% of revenue stream priced off of US$

• Balanced revenue stream (2015: 49% Gas, 51% Condensate/NGL’s)

• Manage production growth giving consideration to• Hedged volumes and Alliance contracted volumes• Replacing PDP reserves with higher netback boes than we are depleting• Q1 2016 production of 8,395 boe/d up from 8,250 2015 exit rate

• One well drilled and waiting on completion

• Continue to focus on margin growth• Higher condensate yields leading to increased revenue per boe• Reducing operating costs and condensate transportation costs

CORPORATE SUMMARY

May 24, 2016 5

CORPORATE INFODEEP BASIN – NORTHWEST ALBERTA

Trading Symbol TSX:DEE

Basic Shares Outstanding 155.5 million

Market Capitalization $179 million

Q1 2016 Production 8,395 boe/d

Dec. 31, 2015 Reserves (P+P) 45.5 mmboe

Net Debt Mar. 31, 2016 $126 million

Credit Dec 31, 2015 $146.5 million

• Capital program focused exclusively on the Bigstone Montney liquids-rich resource development

• Legacy assets: (2,600 boe/d)• Wapiti sold July 2015 for $50 million• Hythe sold November 2015 for $12 million

Wapiti

Tower Creek

Bigstone

Hythe

Dawson Creek

Grande Prairie

Hythe and Wapiti sold in 2015

BIGSTONE – A SINGULAR FOCUS

May 24, 2016 6

Bigstone West Gas Plant

85 mmcf/d

Bigstone

Negus Gas Plant

15 mmcf/d 7-11 Montney Facility

55 mmcf/d

Tower Creek

Montney Acreage

5-8

7-11

5-8 Montney Facility

10 mmcf/d

16-34-59-21W5

Disposal Facility

K3 Facility

25 DEE Producing Montney Horizontals

DOMINANT LAND POSITION

May 24, 2016 7

Resthaven

East Bigstone

Fir

South Bigstone

West Bigstone

ExxonChevron

ATH

DEE

Exxon

ECA

Exxon

Exxon

Conoco

Continue to pursue additional

Montney acquisition/farm-in

opportunities within Greater

Bigstone

• Montney land position has grown to 139 gross (117.1 net)

sections since 2010

• Delphi one of the largest Montney landowners on map sheet

• Delphi continues to be a leader in the technical innovation of

the liquids-rich play

• Development drilling inventory of +100 two mile HZ wells at

East Bigstone

• West Bigstone will require +100 wells to develop

• Delphi drilling 2016 drilling program moving westward

• Industry offset activity is aiding de-risking area

• Continue to pursue land consolidation opportunities

• Owned and operated infrastructure in place

• Expanding to match production growth

STRATEGIC INFRASTRUCTURE

May 24, 2016 8

Rge19 Rge18

Twp 61

Twp 60

Twp 58

Future DEE Amine Plant (2017?)

SemCAMS KA

Delphi Montney production switched to SemCAMS K3 September/14

TCPL

Alliance

SemCAMS K3

Alliance

TCPL

Rge25W5 Rge24 Rge23 Rge22

Delphi 7-11

Saturn Deep Cut TCPL

TCPL

Alliance

TLM BWGP

CFGGS Tie-in option to TLM Edson Plant

for acid gas

Delphi 5-8

New 100% DEE Water Disposal

Well

• Delphi owns significant infrastructure at Bigstone

• 100% owned 55 mmcf/d sour dehy and compression facilities

• 26% ownership in 85 mmcf/d sweet processing plant

• Sour processing capacity at SemCAMS K3

• Delphi water disposal well operational in Q4 2015

• Pursuing plans to further optimize netbacks and project economics

STRATEGIC INFRASTRUCTURE

May 24, 2016 9

Delphi 100% owned Water Disposal Facility

• $3 million project• Less than 1 year payout

• Targeted operating costs savings of:• $2.0 to $2.5 million per year

or• $0.70 per Montney boe

• Targeted completion cost savings of:• $300,000 per well

• Potential to take third party water• Profit center vs cost center• Leduc disposal well capable of

injection in excess of 4,000 bbls/d• Two truck unloading lanes• Simple to increase tank storage as

required

ALLIANCE FIRM TRANSPORTATION SERVICE

May 24, 2016 10

0.0

10.0

20.0

30.0

40.0

50.0

60.0

70.0

80.0

Dec

-15

Feb

-16

Ap

r-1

6

Jun

-16

Au

g-16

Oct

-16

Dec

-16

Feb

-17

Ap

r-1

7

Jun

-17

Au

g-17

Oct

-17

Dec

-17

Feb

-18

Ap

r-1

8

Jun

-18

Au

g-18

Oct

-18

Dec

-18

Feb

-19

Ap

r-1

9

Jun

-19

Au

g-19

Oct

-19

Dec

-19

Feb

-20

Ap

r-2

0

Jun

-20

Au

g-20

Oct

-20

TCPL/Alliance Capacity (mmcf/d)

TCPL Firm Alliance Firm

Q1 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.

26 MONTNEY WELLS DRILLED

May 24, 2016 11

• Drilled 3 HZ wells in 2012

• Conventional gelled oil frac designs

• Extended reach laterals of 2,200 m to 3,000 m

• Drilled 21 HZ wells in 2013 - 2015

• Initial slickwater hybrid frac design• Superior production

performance

• Continued innovation of the slickwater frac design

• Delineation of East Bigstone focused on low-risk high productivity infill drilling

• Drilling 4 to 5 HZ wells in 2016

• Focused on “west side” area

• Higher condensate yields

• Increase well density from 4 laterals per section to 5 or 6

• Significant drilling inventory for 2017 and beyond with ultra-high condensate yields

CLT10 wells

NAL2 wells

3-26

12-17

ATH5 wells

DEI3 wells

To KA Sour Plant

DEE 5-8 Sour Montney Facility

10 mmcf/d

DEE 7-11 Sour Montney Facility

Expanded to 55 mmcf/d in Q1 2016

XTO2015 Drill

CORPORATE AND MONTNEY RESERVES

May 24, 2016 12

29%

1%

31%

47%

PDP

PDNP

PUD

PA

Montney Development (2012 to Q1 2016)

• 26 wells drilled life-to-date (LTD)

• Produced 6.1 million boes in 3.5 years

• Generated $120 million in field operating income

• Cumulative capital of $265 million

• Including $45 million of infrastructure costs

• 2015 PDP FD&A of $10.00 per boe

• LTD netback of $19.65/boe with a recycle ratio of 1.4

19 percent growth in

PDP reserves in 201515,108

19,267

25,520

31,434

21,572

307 281 402 478 292

2011 2012 2013 2014 2015

Probable (mboe)

Proved (mboe)

Reserves /1,000 shares

74,368

40,182

25,074

36,142

61,662

23,796

43,063

42,934

45,463

23,891

2012 2013 2014 2015

Montney Proved Producing Reserves(mboe)

11,626

9,781

4,370

1,178

• 18,625 mboe of dispositions in 2015

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

2,400 – 3,000 30 - 40 1,580 485 131 1,293 1,058 912 811 585

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

02-07 #12 2,702 30 1,116 327 126 940 750 647 570

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

03-26 #15 2,601 30 1,053 330 134 755 592 506 447

13-23 #16 2,161 30 1,556 400 111 1,282 966 820 717

16-27 #17 2,883 40 1,659 413 108 1,296 1,045 890 761

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

13-24 #20 2,716 40 1,526 469 132 1,172 948

14-30 #21 2,729 37 1,840 505 118 1,407 1,112

14-24(4) #22 2,602 37 1,119 435 172 976

14-27(4) #23 2,887 37 1,414 572 180 1,280

13-21(4) #24 2,781 37 1,204 662 291

15-23 #25 2,865 waiting on completion

1,444 456 141 1,210 996 870 766 672

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.

Conventional Fracs (original completion technique)

Slickwater Fracs (new completion technique)

Average Wells #5 through #24

INDIVIDUAL MONTNEY WELL DATA

May 24, 2016 13

• 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

INCREASING CONDENSATE YIELDS

May 24, 2016 14

Geography (East to West)

• Field condensate yields increase• Montney thickens

• Multiple layers to drill• Porosity and Permeability decreases

• Well spacing decreases• Reservoir pressure increases• H2S decreases from 0.80% to sweet

• Access DEE sweet infrastructure• 40 mmcf/d capacity

Frac Innovation

• Larger fracs• Higher pump rates• Higher sand concentrations

• Increasing fracture complexity• Condensate flow improves

3-26

12-17

ATH2015 WellsIP30 CGR

158 to 242 bbl/mmcf

XTO2015 Drill

CGR 260 bbl/mmcf(based on public data)

DEE 12-172013 Drill

IP30 CGR 62 bbl/mmcf

DEE 13-212015 Drill

IP30 CGR 252 bbl/mmcfDEE Type Well

IP30 CGR 70 bbl/mmcf

CONDENSATE YIELDS INCREASING

May 24, 2016 15

$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

2016 Price ForecastAECO Nat Gas: Cdn$1.82/mcfNYMEX Nat Gas: US$2.00/mmbtuWTI: US$38.00/bblCondensate: Cdn$47.00/bblNGLs: Cdn$16.50/bbl

13-21IP30

Recycle Ratio = 1.8

14-24IP30

$10.00/boe increase in revenue

(before hedges)

$7.75/boehedging gain

forecast in 2016

• Recent drilling results achieving higher condensate yields

• Increasing the revenue ($/boe) of the new wells more than Delphi's in-the-money hedges

• New richer wells generate up to a 1.8 PDP recycle ratio on unhedged netbacks

• PDP F&D of $10.00/boe• Cash costs of 16.00/boe

YIELD GROWTH REPLACES HEDGING GAINS IN 2017

May 24, 2016 16

$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

MONTNEY ECONOMIC MODEL

May 24, 2016 17

0

100

200

300

400

500

600

700

800

0

1,000

2,000

3,000

4,000

5,000

6,000

7,000

8,000

0 200 400 600 800 1000 1200

Fie

ld C

on

de

nsa

te R

ate

(b

bl/

d)

Gas

Rat

e (

mcf

/d r

aw)

Flowing Days

Delphi Energy Bigstone Montney

Average All 30+ Stage SW Gas Average Toe Up 30+ Stage SW Gas Type Well Gas

Average All 30+ Stage SW FCondy Average Toe Up 30+ Stage SW FCondy Type Well FCondy

0

5

10

15

20

0

500

1,000

1,500

2,000

0 200 400 600 800 1000 1200

Wel

l Co

un

t

Bo

e/d

Flowing Days

Delphi Energy Bigstone Montney

Average 30+ Stage SW Average Toe Up 30+ Stage SW Type Well Toe Up Well Count

Capital Efficiencies IP 90 day = $5,414 boe/dIP 1 year = $8,631 boe/dIP 2 year = $11,966 boe/d

Target Capital

D,C,E&TI MM$

Initial Sales Production (IP30 - first 30 day average)

Gas mmcf/d

Total Liquids (C3+)(1,2) bbl/mmcf

Total Liquids (C3+)(1,2) bbl/d

Total IP30 boe/d

Total Liquids IP30 (C3+)(1,2) bbl/d

Reserves (sales)

Gas bcf

Liquids (C3+)(1,2) mmbbl

Total mmboe

Economics/Metrics - May 11, 2016 Strip Pricing(3)

NRF MRF

Payout yrs 1.8 1.9

IRR % 49% 46%

NPV 10 MM$ $5.1 $5.3

F&D $/boe $6.13 $6.13

(4) NRF - New Royalty Framework for wells drilled prior to January 1, 2017. M RF - M odernized Royalty Framework for wells drilled after January 1, 2017.

Alberta Royalty Framework(4)

131

695

1,580

695

4.5

0.4

1.1

(3) Strip pricing for 5 years then escalated at 2%/yr thereafter. 2016 prices: Henry Hub $2.48/mmbtu US, $3.19/mmbtu CDN; WTI $48.27/bbl USD; C5

$61.79/bbl CDN. 2017 Prices: Henry Hub $2.96/mmbtu US, $3.80/mmbtu CDN; WTI $49.82/bbl USD; C5 $62.98/bbl CDN.

(1) Stabilized field condensate beyond month six is 46 bbl/mmcf sales

(5) Type Well reserves and production performance are internal management estimates and may not reflect the actual performance of future wells.

Delphi's 17 horizontal toe up M ontney wells at East B igstone with at least 30 stage fracs were time normalized, averaged and used to determine a

proved plus probable reserve estimate. The estimates are used for illustrative purposes and internal corporate planning. 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.

5.3

(2) C3: Propane, C4: Butane, C5: Pentane. Gas plant recovered natural gas liquids estimated at 40 bbl/mmcf sales.

Bigstone Montney Toe Up Two Section Horizontal Hypothetical Type Well30 to 40 stage Slickwater Completion

$7.0

MONTNEY ECONOMIC MODEL

May 24, 2016 18

0

1,000

2,000

3,000

4,000

5,000

6,000

0 200 400 600 800 1,000 1,200

Gas

(m

cf/d

raw

)

Flowing Days

Section 21-60-23W5 Gas Prod vs. Western Bigstone East Type Wellfor CGR Economic Sensitivities

West Type Well 102/15-21-60-23W5 103/13-21-60-23W5

Initial Sales Production (IP30) & Reserve Assumptions:

IP30 Gas Rate 3.6 mmcf/d

1st Month Field Condensate/Gas Ratio (CGR) 185 bbl/mmcf

Gas Reserves 3.9 bcf

Stabilized CGR

after 1st Month Reserves IRR Payout NPV10 IRR Payout NPV10

(bbl/mmcf sales) (mmboe) (years) (MM$) (years) (MM$)

139 1.4 102% 1.2 $11.9 95% 1.2 $12.4

116 1.3 80% 1.4 $9.6 76% 1.4 $10.1

91 1.2 60% 1.6 $7.3 57% 1.7 $7.8

82 1.1 53% 1.8 $6.4 50% 1.9 $6.9

* - Same capital and pricing assumptions as Toe Up Two Section Hypothetical 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

and is constant in the four sensitivities presented above. 102/15-21 has a life to date field condensate to gas ratio (CGR) of 91

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 (March 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. Economics presented here are half cycle, include target capital for

well costs to drill, complete, equip and tie-in, and are provided to illustrate sensitivities to field condensate ratios (or yields).

No costs for land, central facilities, field gathering infrastructure, corporate costs, etc. are included.

Ultra Rich CGR Economic Sensitivities*

MRFNRF

Alberta Royalty Framework

PRODUCTION AND OPERATING MARGIN GROWTH

May 24, 2016 19

0

1,000

2,000

3,000

4,000

5,000

6,000

7,000

8,000

2012 2013 2014 2015 2016 (F)

Montney Production (boe/d)

10-15% Growth in 2016 vs 2015

0

200

400

600

800

1,000

1,200

1,400

1,600

2012 2013 2014 2015 2016 (F)

Field Condensate Production (boe/d)

Consistent condensate yields over time have

supported growth

3256 55 55 56

10

13 11 10 10

11

13 12 13 1314

14 17 19 18

-

20

40

60

80

100

120

2012 2013 2014 2015 2016 (F)

Field Condensate Plant Condensate Butane Propane

Montney Liquids Yield (bbls/mmcf)

0.00

2.00

4.00

6.00

8.00

10.00

12.00

14.00

2012 2013 2014 2015 2016 (F)

Montney Operating Costs ($/boe)

DELPHI WELL COST IMPROVEMENTS

May 24, 2016 20

0

5,000

10,000

15,000

20,000

2012 2013 2014 2015 2016Target

($/boe/d)

IP90 Day Capital Efficiencies

90 Day D&C $ Efficiency ($/boe/d) 90 Day Comp $ Efficiency ($/boe/d)

IP 90 production data taken from public sources for 2012 to 2014

Montney Capital Efficiencies

• Average drilling and completion costs per

well have trended down by 26 percent from

$11.0 million in 2012

• Latest D&C well costs were $7.0 million

compared to $10.4 in 2014

• New D&C target set at $6.5 million

• Further cost savings are being targeted

• Water disposal

• Frac design

0

100

200

300

400

500

600

700

0

2,000

4,000

6,000

8,000

10,000

12,000

2012 2013 2014 2015 Recent 2016Target

Cost per Frac Stage ($000)D&C Costs ($ 000)

DEE Well CostsAvg. Drill Costs Avg. Comp. Costs Avg. Comp. $/Stage

Well costs down 36 percent

DRILLING PLANS MOVING WEST

May 24, 2016 21

Conoco Completed in 2013

Conoco Completed in 1H 2014

Conoco Completed in 2015

Delphi 9-4 WellConventional

Gelled Oil Frac in 2012

Moving West

• Montney pay thickness increasing • 6 laterals per section spacing• Two layers to drill

• Natural gas is sweet • DEE sweet infrastructure

• 40 mmcf/d capacity

• Condensate and NGL yields:• 2 to 4 times greater than

East Bigstone type curve

• Slickwater “frac design”

Competitor well producing 95 bbl/mmcf condensate

DEE activity planned for 2H 2016 and 2017

25 well inventory just in this small area

($200 million in capital)

4 Competitor wells drilled and

completed

BIGSTONE CRETACEOUS: OPTIONALITY

May 24, 2016 22

Bigstone Bluesky to Gething Cross Section

LOCATION

Permeability barriers and baffles in the 1-

18-60-24W5 Gething core

Area and Play Attributes

Delphi operated / high working interest

• Multiple zones are prospective, with Gething most

productive

• Delphi has over 1100 boed production, with 16%

liquids

Delphi infrastructure in place with low OPEX

• NGL content : 28 bbl/mmcf Gething

• Liquids and oil in Cardium, Dunvegan and Second

White Specks

• Falher, Wilrich, Paddy and Cadomin prospective in

several areas

Tight Sand Exploitation: The Past and The PresentUntitled

Untitled

Untitled

Untitled

Untitled

Untitled

regional sandhigh perm interval

good well the new paradigmgreat well

Delphi has drilled 25 vertical Gething wells with 98% success since 2005

HZ multi-stage fracing technology is the next generation of development

12-16-60-23W5 Hz Gething

Drilled 2012

789 m Hz length

10 stage ball drop,

30T N2 foam frac

“Concept Well” to prove play

Bigstone Gething Land

TOU’s Leland Falher>45 Bcf Cumm

COMMODITY PRICES: MANAGING VOLATILITY

May 24, 2016 23

Volatility creates hedging opportunities

CDN/US FX

CONSISTENT AND PROVEN RISK MANAGEMENT PROGRAM

May 24, 2016 24

Event driven hedging strategy with a long term

view of a relatively balanced supply/demand

market with “events”:

• Mitigates commodity price risk and

provides revenue and cash flow certainty

• Contracts often undertaken around price

spike events affecting the futures curve

• 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 percent

• Increased cash flow by 18 percent

• Added $3.35 per boe to the netback

• Strategy is proven and repeatable

over 2 to 4 year “peak to trough”

event cycles -$15

-$10

-$5

$0

$5

$10

$15

$20

$25

$30

$35

2006 2007 2008 2009 2010 2011 2012 2013 2014 2015

Hedging Gains/Losses ($millions)

Polar Vortex lifting natural gas prices in 2014

Natural gas price spike in 2008

Steady decline of natural gas prices from 2009 to 2013

Collapse of both natural gas and crude oil prices

-$10

$0

$10

$20

$30

$40

2006 2007 2008 2009 2010 2011 2012 2013 2014 2015

Hedging Contribution to Cash Flow ($/boe)

Operating cash flow per boe Hedging gains(losses) per boe

HEDGES PROTECTING CASH FLOW

May 24, 2016 25

Natural Gas (Cdn) Apr – Dec 2016 2017Volume (mmcf/d) 2.4 2.4% Hedged (1) 7% 7%Hedge Price (Cdn $/mcf) (2) $3.89 $3.96Strip Price (Cdn $/mcf) $1.91 $2.71

Natural Gas (US) Apr – Dec 2016 2017 2018 2019Volume (mmbtu/d) 23.5 17.1 5.0 2.0% Hedged (1) 67% 49% 14% 6%Hedge Price (US $/mmbtu) $3.50 $3.19 $2.79 $2.81Strip Price (US $/mmbtu) $2.43 $2.97 $2.99 $3.00% Hedged in Cdn $ (3) 100% 100% 99% 100%Hedge Price (Cdn $/mmbtu) (4) $4.50 $4.23 $3.70 $4.02

Crude Oil Apr – Dec 2016 2017Volume (bbls/d) 800 300% Hedged (1) 43% 16%Floor Price (WTI Cdn $/bbl) $78.50 $60.00Ceiling Price (WTI Cdn $/bbl) (5) $85.00 $60.00Strip Price (WTI Cdn $/bbl) $58.62 $60.95

(1) Percent hedged is based on expected 2016 average natural gas production of approximately 35 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

March 31, 2016 Mark-to-Market value of approximately $23.1 million

2016 GUIDANCE

May 24, 2016 26

2016

Guidance

Average Annual Production (boe/d) 8,300 – 8,800

Exit Production Rate (boe/d) 8,500 – 9,500

NYMEX Natural Gas Price (US $ per mmbtu) $2.00

WTI Oil Price (US $ per bbl) $38.00

Natural Gas Liquids Price (Cdn $ per bbl) $16.50

Foreign Exchange Rate (US/Cdn) 1.35

Well Count 4.0 – 5.0

Net Capital Program ($ million) $33.0 - $38.0

Funds from Operations (“FFO”) ($ million) $32.0 - $37.0

Net Debt at December 31 ($ million) $121.0 - $126.0

Net Debt / Q4 FFO (annualized) 3.0 – 3.5

SENSITIVITIES TO 2016 FORECAST

May 24, 2016 27

In the context of 2016 forecast pricing: (US$38.00 WTI and US$2.00 NYMEX)

• US$0.50/mmbtu change in NYMEX:• Cdn$650,000 cash flow

• US$5.00/bbl change in WTI • Cdn$2.5 million cash flow

• CAPEX AND OPEX efficiencies:• D&C costs down 35 percent• Focused on margin growth

• Significant hedge position for 2016 and 2017

2016 CAPEX / CF MATRIX

Number of 2016 Exit Rate US$ WTI / US$2.00 NYMEX

Gross Wells Production Growth $30.00 $40.00 $50.00 $60.00

4 0% 122% 106% 96% 87%

5 15% 140% 122% 110% 100%

6 25% 152% 131% 118% 107%

2016 DEBT / CASH FLOW MATRIX

Number of US$ WTI / US$2.00 NYMEX

Gross Wells $30.00 $40.00 $50.00 $60.00

4 4.5 3.5 3.2 2.8

5 4.5 3.5 3.2 2.8

6 4.4 3.4 3.1 2.7

2017 AND BEYOND

May 24, 2016 28

Levers Still to be Pulled in an “Oil Lower for Much Longer” Scenario:

• Operating efficiency gains lifting “unhedged” netbacks through 2016 and 2017

• Capital efficiency gains

• New well innovations are continuing

• Significant existing infrastructure and processing capacity in place

• No significant infrastructure capital required in this environment

• 20 mmcf/d of owned sour Montney capacity available• 139 sections to develop

• 40 mmcf/d of owned sweet processing capacity available• OPEX 40 percent lower than sour Montney• For sweet Montney as we drill west• HZ Gething play being delineating with each Montney well

• Very low operating costs with existing infrastructure• 80 sections to develop

SUMMARY

May 24, 2016 29

• Bigstone Montney is a Top Tier growth asset

• Large Montney land base of 139 sections

• Favorable economics and attractive capital efficiencies

• Remains economic in the trough of the commodity price cycle

• Continuing to successfully to drive down costs (OPEX, TRANS, G&A and CAPEX)

• Cash generating capability supported by Montney margin and production growth

• Montney netbacks top tier with NGL cocktail mix

• Condensate yields will increase with focused “west side” drilling activity

• Stable life-to-date NGL Yields (C3+) of approx. 96 bbls/mmcf

• Average 69% Condensate

• Selling approximately 85 percent of our natural gas production into Chicago market

• Hedges in place through 2019

• Expecting Bigstone Montney development to increase in 2017

May 24, 2016 30

APPENDIX

EVOLUTION OF THE WORLD-CLASS MONTNEY PLAY

May 24, 2016 31

Elmworth

Wapiti

Kakwa

DelphiBigstone

Source of Data: geoSCOUT

Large data set488 Montney wells on

production

EVOLUTION: PACE OF DRILLING ACCELERATING

May 24, 2016 32

Drilling remains active with 106 Montney wells rig released YTD 2015

• Only 10 wells reporting Montney production as of the date of this analysis

This analysis is based upon wells which have Montneyproduction reported and available to the public. Data has

been sourced from geoSCOUT.

0

50

100

150

200

2008 2009 2010 2011 2012 2013 2014 2015

Producing Wells by Rig Release DateTotal Wells: 488

0102030405060708090

100Producing Wells by Operator

0

500

1,000

1,500

2,000

2,500

3,000

3,500

4,000

2008 2009 2010 2011 2012 2013 2014 2015

IP180 (mcf/d) by Year

EVOLUTION: WELL LENGTH INCREASING

May 24, 2016 33

0

500

1,000

1,500

2,000

2,500

3,000

2008 2009 2010 2011 2012 2013 2014 2015

Average Horizontal Length (m)

Horizontal Length (m)

Delphi Ave

0

20

40

60

80

100

120

140

160

180

0-1,000 1,001-1,500 1,501-2,000 2,001-2,500 2,501-3,000 3,000+

Number of Wells

0

500

1,000

1,500

2,000

2,500

3,000Average Horizontal Length (m)

EVOLUTION: FRAC STAGES INCREASING

May 24, 2016 34

0

5

10

15

20

25

30

2008 2009 2010 2011 2012 2013 2014 2015

Average Number of Frac Stages/Well

Frac Stages per Well

Delphi Ave

Evolution of frac design/recipe has also had a significant positive impact to productivity

0

20

40

60

80

100

120

140

160

0 - 10 11 - 15 16 - 20 21 - 25 26 - 30 31 - 35 36 - 40

Number of Wells

0

5

10

15

20

25

30

35Average Number of Frac Stages/Well

EVOLUTION: WELL PRODUCTIVITY INCREASING

May 24, 2016 35

1518 19 60 36

59 33 3866

18

60 23

0500

1,0001,5002,0002,5003,0003,5004,0004,500

IP90 (mcf/d)441 wells

IP’s based on publicly reported gas rates only

1714 46

18 30 4825 36

55 1516 47

0500

1,0001,5002,0002,5003,0003,5004,0004,500

IP180 (mcf/d)362 wells

159 29

28 1325

2231

32 1539 11

0500

1,0001,5002,0002,5003,0003,5004,000

IP365 (mcf/d)260 wells

0

500

1,000

1,500

2,000

2,500

3,000

3,500

4,000

2008 2009 2010 2011 2012 2013 2014 2015

IP180 (mcf/d)

Delphi Ave

300, 500 – 4th Avenue SW

Calgary, Alberta T2P 2V6

P (403) 265-6171

F (403) 265-6207

info@delphienergy.ca

www.delphienergy.ca

May 24, 2016 36