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CORPORATE PRESENTATION MARCH 2016 DELPHI: FORWARD-LOOKING STATEMENTS The presentation contains forward-looking statements and forward-looking information within the meaning of applicable Canadian securities laws. These statements relate to


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SLIDE 1

CORPORATE PRESENTATION

MARCH 2016

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SLIDE 2

DELPHI: FORWARD-LOOKING STATEMENTS

The presentation contains forward-looking statements and forward-looking information within the meaning of applicable Canadian securities laws. These statements relate to future events

  • r 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

  • il 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. 2 March 2016

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SLIDE 3

A MONTNEY FOCUSED SUSTAINABLE BUSINESS MODEL

3

  • Delphi’s Bigstone Montney remains a Top Tier growth asset:
  • Maintains favorable economics in the current commodity price environment
  • Well payouts at 1.9 years on current strip
  • Free cash generated at payout remains significant
  • Significant drilling inventory on 139 sections of land
  • Cash generating capability remains healthy in current environment
  • Balanced revenue stream (2015: 49% Gas, 51% Condensate/NGL’s)
  • Significant commodity hedge position in 2016 and 2017
  • Driving capital and opex cost structures lower
  • Drilling and completion costs down 35 percent from 2014
  • Montney operating costs down 9 percent in 2015
  • Continued modest pace of drilling in 2016 to a cash flow only CAPEX budget
  • Focused on cost efficiency and balance sheet preservation
  • Reduced debt by 30 percent with Wapiti and Hythe dispositions in 2015
  • Growth in netback versus growth in production

March 2016

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SLIDE 4

DELPHI: CORPORATE

4

CORPORATE INFO DEEP BASIN – NORTHWEST ALBERTA Trading Symbol TSX:DEE Basic Shares Outstanding 155.5 million Market Capitalization $157 million Q4 2015 Production 8,814 boe/d

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

Net Debt Dec. 31, 2015 $122 million Credit Dec 31, 2015 $146.5 million

March 2016

  • 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

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SLIDE 5

DELPHI: BIGSTONE - A SINGULAR FOCUS

March 2016 5 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

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SLIDE 6

BIGSTONE MONTNEY: DOMINANT LAND POSITION

6

Resthaven East Bigstone Fir South Bigstone West Bigstone

Exxon Chevron ATH DEE Exxon ECA Exxon Exxon Conoco

  • 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
  • Industry is de-risking area
  • Continue to consolidate land and infrastructure

Continue to pursue additional Montney acquisition/farm-in

  • pportunities within Greater

Bigstone

March 2016

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SLIDE 7

BIGSTONE MONTNEY: STRATEGIC INFRASTRUCTURE

7 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 80 mmcf/d sweet

processing plant

  • Sour processing capacity at SemCAMS K3
  • Lowered fee structure by approx. $2 per

Montney boe

  • Higher plant NGL recoveries
  • Greater long-term capacity available to meet

Delphi’s growth plans

  • Delphi water disposal well operational in Q4

2015

  • Pursuing plans to further optimize netbacks

and project economics

March 2016

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SLIDE 8

BIGSTONE MONTNEY: STRATEGIC INFRASTRUCTURE

8

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
  • r
  • $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

  • Currently disposing on vacuum
  • Two truck unloading lanes
  • Simple to increase tank storage as

required

March 2016

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SLIDE 9

BIGSTONE MONTNEY: TCPL/ALLIANCE SERVICE

9 March 2016

0.0 10.0 20.0 30.0 40.0 50.0 60.0 70.0 80.0 Dec-15 Feb-16 Apr-16 Jun-16 Aug-16 Oct-16 Dec-16 Feb-17 Apr-17 Jun-17 Aug-17 Oct-17 Dec-17 Feb-18 Apr-18 Jun-18 Aug-18 Oct-18 Dec-18 Feb-19 Apr-19 Jun-19 Aug-19 Oct-19 Dec-19 Feb-20 Apr-20 Jun-20 Aug-20 Oct-20

TCPL/Alliance Capacity (mmcf/d) TCPL Firm Alliance Firm

Q4 2015 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.

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SLIDE 10

DELPHI MONTNEY: OPEX AND NGL YIELDS

10

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) Montney Operating Costs

  • Operating costs being reduced as a result of

economies of scale, processing arrangements and reduction in cost of services

  • Further savings of 12 – 15 percent targeted:
  • Water disposal
  • Compressor fuel gas optimization
  • General service cost contraction

March 2016

32 56 55 55 56 10 13 11 10 10 11 13 12 13 13 14 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) Liquids Yield Improved with Slickwater Fracs

  • Montney average liquids yield over the past

three years ~96 bbls/mmcf (69% field and plant condensate)

  • “Westside” exhibiting significantly higher

condensate yields

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SLIDE 11

16-30 5-2 CLT 10 wells NAL 2 wells 15-10 2-1 2-7 8-21 3-26 12-17 16-15 ATH 5 wells DEI 3 wells

To KA Sour Plant

16-24

BIGSTONE MONTNEY: 26 WELLS DRILLED

11

  • Drilled 3 HZ wells in 2012
  • Two mile HZ’s with laterals of 2,200

m to 3,000 m

  • Frac’d using conventional gelled oil

frac designs

  • Drilled 7 HZ wells in 2013
  • HZ’s with laterals of 1,400 m to

3,000 m

  • Frac’d using slickwater hybrid

design

  • Superior production performance

to initial 3 gelled oil frac wells

  • Drilled 8 HZ wells in 2014
  • Further delineation of the East

Bigstone area

  • Further evolution of the slickwater

frac design

  • Drilled 6 HZ wells in 2015
  • Focused on low-risk high

productivity infill drilling

  • Drilling 4-5 HZ wells in 2016
  • Focused on “westside” area of

higher condensate yields

March 2016

DEE 5-8 Sour Montney Facility 10 mmcf/d DEE 7-11 Sour Montney Facility Expanded to 55 mmcf/d in Q1 2016

DEE activity planned for 2H 2016 and 2017

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SLIDE 12

Conoco Completed in 2013 Conoco Completed in 1H 2014 Conoco Completed in 2015 Delphi 9-4 Well Conventional Gelled Oil Frac in 2012 3 Competitor wells drilled and competed Competitor well drilled and completed

WEST BIGSTONE: ADDITIONAL MONTNEY UPSIDE

12 March 2016

West Bigstone Montney:

  • 27 sections (100% WI)
  • Upper and middle Montney increasing pay

thickness

  • Greater than 4 wells per section likely

required

  • Natural gas is sweet to marginally sour
  • 100% DEE sweet infrastructure in place
  • Condensate and NGL yields likely 2 to 3 times

greater than East Bigstone

  • Slickwater “frac design” being perfected with

industry activity in the area

Competitor well producing 95 bbl/mmcf condensate DEE activity planned for 2H 2016 and 2017 25 well ($200 million in capital) inventory just in this small area

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SLIDE 13

BIGSTONE MONTNEY: PRODUCTION GROWTH

13

Montney Production Still Growing in 2016

  • Average Montney production for 2016 forecast to

grow by 10 to 15 percent

2,000 4,000 6,000 8,000 2012 2013 2014 2015 2016 (F)

Montney Production (boe/d)

10-15% Growth in 2016 vs 2015

March 2016

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

10.00 15.00 20.00 25.00 30.00 35.00 50 100 150 200 250 Revenue ($/boe) Field Condensate Yield (bbl/mmcf raw)

Revenue Sensitivity on Field Condensate Yield

15-30 14-27 IP30 Type Well

15-21 Life to date

Realized Prices Natural Gas: Cdn$2.70/mcf Condensate: Cdn$47.00/bbl NGLs: Cdn$18.00/bbl

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SLIDE 14

Number IP30 IP30 IP30 IP90 IP180 IP270 IP365 IP 2yr HZ Length

  • f 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 1,629 449 119 1,306 1,083 943 843 614 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 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 14-30 #21 2,729 37 1,840 505 118 1,407 14-24(4) #22 2,602 37 1,119 435 172 976 14-27(4) #23 2,887 37 1,414 572 180 13-21(4) #24 2,781 37 1,457 445 133 1,206 991 870 766 660 Conventional Fracs (original completion technique) Slickwater Fracs (new completion technique) Average Wells #5 through #23 Well(2) Initial Production (IP) Rate Well Performance (1) Type Well

(1) Average production calculated on operating days, excludes non-producing days. Includes estimated NGL gas plant recoveries. (2) Wells numbered chronologically. (3) Initial Exploration Well on Delphi's South Bigstone Lands. (4) Initial production restricted (slow -back) to tubing flow only to evaluate impact on field condensate yield.

BIGSTONE MONTNEY: INDIVIDUAL WELL DATA

14 March 2016

  • 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

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SLIDE 15

BIGSTONE MONTNEY COMPARED TO A LARGER DATA SET

15 March 2016

Elmworth Wapiti Kakwa Delphi Bigstone

Source of Data: geoSCOUT

Large data set 488 Montney wells on production

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SLIDE 16

15 18 19 60 36 59 33 38 66 18 60 23 500 1,000 1,500 2,000 2,500 3,000 3,500 4,000 4,500

IP90 (mcf/d) 441 wells

EVOLUTION: WELL PRODUCTIVITY INCREASING

16 March 2016

IP’s based on publicly reported gas rates only

17 14 46 18 30 48 25 36 55 15 16 47 500 1,000 1,500 2,000 2,500 3,000 3,500 4,000 4,500

IP180 (mcf/d) 362 wells

15 9 29 28 13 25 22 31 32 15 39 11 500 1,000 1,500 2,000 2,500 3,000 3,500 4,000

IP365 (mcf/d) 260 wells

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

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SLIDE 17

EVOLUTION: DELPHI WELL COST IMPROVEMENTS

17

5,000 10,000 15,000 20,000 2012 2013 2014 2015 2016 Target

($/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

  • Net of GORR funding arrangement Delphi

capital costs are $5.0 to $5.5 million per well

  • IP365 = $6,500 / boe/d
  • New D&C target set at $6.5 million
  • Further cost savings are being targeted
  • Water disposal
  • Frac design

100 200 300 400 500 600 700 2,000 4,000 6,000 8,000 10,000 12,000 2012 2013 2014 2015 Recent 2016 Target

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

  • Avg. Drill Costs
  • Avg. Comp. Costs
  • Avg. Comp. $/Stage

Well costs down 36 percent

March 2016

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SLIDE 18

BIGSTONE MONTNEY: ECONOMIC MODEL

18 March 2016

3 6 9 12 15 18 500 1,000 1,500 2,000 2,500 3,000 100 200 300 400 500 600 700 800 Producing Well Count

Production boe/d & bbl/d Producing Days

Delphi Energy Bigstone Montney Average 30+ Stage Slickwater Hybrid Well

Typecurve Total Sales (boe/d) Average 30+ Stage HZ Total Sales (boe/d) Typecurve Field Condensate Average 30+ Stage HZ Field Condensate (bbl/d)

Capital Efficiencies IP 90 day = $4,000 boe/d IP 1 year = $6,500 boe/d IP 2 year = $10,000 boe/d

GLJ Jan. 2014 Pricing(1) Capital Target Capital (D,C,E&TI) MM$ $9.2 Economics/Metrics Payout yrs 0.9 ROR % 140% NPV 10 MM$ $18.5 F&D $/boe $7.75

(1) 2014 Prices: AECO $4.03/mcf CDN; Chicago/Midwest $4.58/mcf CDN; WTI $97.50/bbl USD; C5 $105.20/bbl CDN

Original Economics

  • Jan. 13, 2016

Strip Pricing(1) GLJ Jan. 2016 Pricing(2) Capital Target Capital (D,C,E&TI) MM$ Initial Production (day 1) Gas mmcf/d raw Initial Field Condensate bbl/mmcf sales Plant C3+ NGL Recovery bbl/mmcf sales Initial Production (IP30 - first 30 day average) Gas mmcf/d raw Total Liquids (C3+)(3,4) bbl/mmcf sales Total Liquids (C3+)(3,4) bbl/d Total IP30 boe/d Total Liquids IP30 (C3+)(3,4) bbl/d Reserves (sales) Gas bcf Liquids (C3+)(3,4) mmbbl Total mmboe Economics/Metrics Payout yrs 1.9 1.5 ROR % 49% 75% NPV 10 MM$ $6.2 $9.9 F&D $/boe $6.02 $6.02

(3) Stabilized Field Condensate beyond first month is 46 bbl/mmcf sales (4) C3: Propane, C4: Butane, C5: Pentane

670 120

Delphi Energy - Bigstone Montney Two Section Horizontal Type Well

(2) 2016 Prices: AECO $2.76/mcf CDN; Chicago/Midwest $3.72/mcf CDN; WTI $44.00/bbl USD; C5 $60.79/bbl CDN (1) 2016 Prices: AECO $2.45/mcf CDN; Chicago/Midwest $3.52/mcf CDN; WTI $35.29/bbl USD; C5 $50.69/bbl CDN (5) Type Well Reserves and Production performance are internal management estimates and may not reflect the actual performance of the wells. The estimates are used for illustrative purposes and internal corporate planning. Half cycle economics include well costs to drill, complete, equip and tie-in. No costs for land, central facilities, main gathering infrastructure, corporate costs, etc. are included.

30 to 40 stage Slickwater Completion

6.4 39 80 7.0 $7.0 1.2 0.4 4.6 670 1,600

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SLIDE 19

DELPHI: A DIRECTIONAL LOOK AT 2016

19 March 2016

2016 Priorities Through This Structural Reset:

  • Maintain financial flexibility
  • Capex in the context of cash flow
  • Significant hedge position for 2016 volumes
  • 75% of natural gas and 43% of field and plant condensate
  • 95% of revenue stream priced off of US$
  • Manage production giving consideration to:
  • Producing largely within the context of the hedge book
  • Manage production within Alliance contracted volumes
  • Production “flat to up slightly” over the year; replacing PDP reserves
  • Continue to reduce operating costs and lower cost structure
  • Water disposal well
  • New fuel gas source with additional compression reducing maintenance costs
  • Condensate trucking cost reduction/optimization
  • Continue to improve new well capital efficiencies through innovation
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SLIDE 20

DELPHI: 2017 AND BEYOND

20 March 2016

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
  • 20 mmcf/d of owned sour Montney capacity available
  • 139 sections to develop
  • 30 mmcf/d of owned sweet processing capacity available
  • HZ Gething development getting competitive with the Montney
  • Very low operating costs with existing infrastructure
  • Realized netbacks becoming comparable
  • 80 sections to develop
  • 2017 - 2019 natural gas hedges remain attractive with FX futures curve
  • Targeting 60 to 80 percent hedged on natural gas going into 2017
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SLIDE 21

DELPHI: CONSISTENCY OF RISK MANAGEMENT PROGRAM

  • Risk management contracts generally put in place 12-18 months in

advance

  • Contracts often undertaken around price spike events
  • Over a 10 year period risk management program has increased

revenue by 10% and cash flow by 20%

March 2016 21

  • 15
  • 10
  • 5

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

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SLIDE 22

DELPHI: HEDGES PROTECTING CASH FLOW

22

Natural Gas (Cdn) 2016 2017 Volume (mmcf/d) 2.8 2.4 % Hedged (1) 8% 7% Hedge Price (Cdn $/mcf) (2) $3.84 $3.96 Strip Price (Cdn $/mcf) $1.83 $2.77 Natural Gas (US) 2016 2017 2018 2019 Volume (mmcf/d) 23.5 15.0 5.0 2.0 % Hedged (1) 67% 43% 14% 6% Hedge Price (US $/mcf) $3.50 $3.23 $2.79 $2.81 Strip Price (US $/mcf) $2.22 $2.80 $2.87 $2.93 % Hedged in Cdn $ (3) 99% 113% 99% 100% Hedge Price (Cdn $/mcf) (4) $4.50 $4.28 $3.70 $4.02 Average Natural Gas Hedge Price (Cdn $/mcf) $4.43 $4.24 $3.70 $4.02 Crude Oil 2016 Volume (bbls/d) 800 % Hedged (1) 43% Floor Price (WTI Cdn $/bbl) $78.50 Ceiling Price (WTI Cdn $/bbl) (5) $85.00 Strip Price (WTI Cdn $/bbl) $55.47

(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 (6) A complete listing of individual risk management contracts is included in Note 4 of the December 31, 2015 Financial Statements

December 31, 2015 Mark-to-Market value of approximately $18.5 million

March 2016

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SLIDE 23

DELPHI: 2016 GUIDANCE

23

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

March 2016

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SLIDE 24

DELPHI: SENSITIVITIES TO 2016

24 March 2016

In the context of current strip pricing:

(US$35 WTI and US$2.00 NYMEX)

  • CAPEX AND OPEX cost efficiencies:
  • D&C costs down 35 percent
  • Cash netbacks increasing with realized

permanent cost reductions

  • Significant hedge position for 2016 and 2017
  • Bigstone Montney continues to deliver

economic returns

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

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SLIDE 25

DELPHI: SUMMARY

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  • 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
  • Hedges in place through 2018
  • Cash generating capability supported by Montney growth
  • Montney field netbacks top tier with NGL cocktail mix
  • NGL Yields (C3+ ) of approx. 96 bbls/mmcf
  • Average 69% Condensate
  • Condensate yields can increase further through “Westside” drilling activity
  • Continue to drive down costs (OPEX and CAPEX)
  • Alliance delivery service for December 1, 2015 ensures delivery of natural gas to market
  • Expecting Bigstone Montney development to increase in 2016:
  • Return to growth in 2016
  • Reduction in well costs more than offsetting a moderated pace of spending in 2015

March 2016

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SLIDE 26

APPENDIX

26

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SLIDE 27

EVOLUTION OF THE WORLD-CLASS MONTNEY PLAY

27 March 2016

Elmworth Wapiti Kakwa Delphi Bigstone

Source of Data: geoSCOUT

Large data set 488 Montney wells on production

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SLIDE 28

EVOLUTION: PACE OF DRILLING ACCELERATING

28 March 2016

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 Montney production reported and available to the public. Data has been sourced from geoSCOUT.

50 100 150 200 2008 2009 2010 2011 2012 2013 2014 2015

Producing Wells by Rig Release Date Total Wells: 488

10 20 30 40 50 60 70 80 90 100

Producing Wells by Operator

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

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SLIDE 29

500 1,000 1,500 2,000 2,500 3,000 2008 2009 2010 2011 2012 2013 2014 2015

Average Horizontal Length (m)

EVOLUTION: WELL LENGTH INCREASING

29 March 2016

Horizontal Length (m)

Delphi Ave

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

500 1,000 1,500 2,000 2,500 3,000

Average Horizontal Length (m)

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SLIDE 30

5 10 15 20 25 30 2008 2009 2010 2011 2012 2013 2014 2015

Average Number of Frac Stages/Well

EVOLUTION: FRAC STAGES INCREASING

30 March 2016 Frac Stages per Well

Delphi Ave

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

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

5 10 15 20 25 30 35

Average Number of Frac Stages/Well

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SLIDE 31

15 18 19 60 36 59 33 38 66 18 60 23 500 1,000 1,500 2,000 2,500 3,000 3,500 4,000 4,500

IP90 (mcf/d) 441 wells

EVOLUTION: WELL PRODUCTIVITY INCREASING

31 March 2016

IP’s based on publicly reported gas rates only

17 14 46 18 30 48 25 36 55 15 16 47 500 1,000 1,500 2,000 2,500 3,000 3,500 4,000 4,500

IP180 (mcf/d) 362 wells

15 9 29 28 13 25 22 31 32 15 39 11 500 1,000 1,500 2,000 2,500 3,000 3,500 4,000

IP365 (mcf/d) 260 wells

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

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SLIDE 32

300, 500 – 4th Avenue SW Calgary, Alberta T2P 2V6 P (403) 265-6171 F (403) 265-6207 info@delphienergy.ca www.delphienergy.ca

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