corporate strategy presentation - delphi … 1 20… · financial outlook information contained in...

CORPORATE STRATEGY

PRESENTATION

DECEMBER 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.

December 2016

CORPORATE SNAPSHOT

KEY OPERATIONAL FIGURES

Q3 2016 Production boe/d 8,239 (64% gas)

Dec. 31, 2015 Reserves (P+P) (mmboe) 45.5 (67% gas)

2016 GUIDANCE

Average Annual Production (boe/d) 7,700 – 8,000

Exit Production Rate (boe/d) (2)

Under Review

2015 Production Rate Exit 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 (2)

Under Review

Net Capital Program ($ million) (2)

Under Review

Funds from Operations (“FFO”) ($ million) $31.0 - $34.0

(1) Bank debt as of June 2016 includes working capital and $6.0 million of LIC’s(2) 2016 Guidance under ongoing review due to pending Partner Transaction

Grande Prairie

Bigstone

Montney

Edmonton

Calgary

December 2016 3

CORPORATE INFORMATION

Ticker Symbol TSX:DEE

Basic Shares Outstanding (mm) 155.5

Market Capitalization (mm) $175.0

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 138 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

Considerable production growth targets are achievable utilizing existing major infrastructure

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% and operating costs down 30%, since 2014

Added $95 million in cash as a result of an exceptional hedging program

Significant hedged position in place through 2019

Secured firm service with Alliance to access Chicago gas market for better pricing and fewer curtailments

Reduced debt by 30% from the sale of non-core assets – now 100% focused at Bigstone

Replacing PDP reserves with higher netback boe’s than depleting – turning $1 spent into $2 returns

Achieving targets within cash flow to accelerate 2017 growth with increased liquidity

Moderating short-term pace of spend while preserving long-term growth inventory

Frac innovations and increased condensate yields leading to better margins

Delivering top quartile PDP F&D costs and recycle ratios

Top tier well results and capital efficiencies – 2 mile extended reach drilling improving overall well results

Exceptional management team with a track record of value creation

WORLD CLASS

MONTNEY GROWTH

ASSET

100% OPERATIONAL

CONTROL

MARKET ACCESS &

EXCEPTIONAL RISK

MANAGEMENT

RESPONSIBLY

MANAGED

PROFITABLE GROWTH

EXECUTIONAL

EXCELLENCE

4December 2016

5

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

* 473 Wells with IP90 or greater

Elmworth

December 2016

PARTNER TRANSACTION - LETTER OF INTENT

6

Deal Status:• LOI executed November 4, 2016

• P&S to be executed by November 30, 2016

• Planned closing prior to December 22, 2016

$40 Million Joint Drilling Program

Delphi will retain operatorship of the

Montney capital program, production

and facilities.$30 Million Cash Consideration

Delphi will contribute 15% of the drilling and completion costs ($6 million)

while retaining a 65% working interest in the wells;

The Partner will carry the remaining 50% of Delphi’s share of the drilling and

completion costs, to a maximum of $20 million;

The program contemplates 5 – 6 wells drilled before July 15, 2017

Delphi will receive $30 million in cash at closing as equalization consideration

Transaction Assets

The Partner will increase working interests, to varying degrees, in partially developed and undeveloped lands, production and

infrastructure;

450 barrels of oil equivalent (“boe”) per day (approx. 5% of its productive capability)

Total proved reserves of 2.8 million boe (approx.12% of corp.) and associated future development capital of $24.1 million (before escalation)

Total proved plus probable reserves of 7.3 million boe (approx.16% of corp.) and associated FDC of $59.3 million (before escalation)

The Partner will receive a 35% working interest in Delphi’s 100% owned sour processing infrastructure

Delphi will assign various working interests in its land base at Bigstone Montney to the Partner;

Delphi will hold 65% and the Partner will hold 35% of the combined interests;

Delphi’s total developed, partially developed and undeveloped land position will change from approx. 117 net sections (138 gross) to 87 net

sections (143 gross);

Delphi will assign a total of 25.4 net undeveloped sections to the Partner

Delphi will receive a total of 2.25 net undeveloped sections from the Partner

December 2016

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 has de-

risked area

South Bigstone – exploration opportunity

Super-major presence and development

activity; Exxon, Chevron, & ConocoPhillips

operate in the general area

Current Montney land position grown

from 4.0 to 138 gross (117 net) sections

since 2010;

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

7

WEST BIGSTONE

SOUTH BIGSTONE

Other

December 2016

EAST BIGSTONE

28 BIGSTONE MONTNEY WELLS DRILLED

8

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 138 sections for 2017 and beyond;

Increasing condensate yields

Continued cost reduction

Progressive improvements in Drilling Results

Legend

2012-2015 (24 wells)

2016 (4 – 5 wells)

Fully Developed Sections

DEE 7-11 Sour Facility

Expanded to 55 mmcf/d in

Q1 2016

DEE 5-8 Sour Facility

10 mmcf/d

December 2016

8 Sections Fully Developed

95% of Production

Excluded from Equalization

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

$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

9

DEE 7-11

55 mmcf/d

Montney Facility

To SemCAMS

Future DEE Amine Plant

To TCPL

TLM BWGP85 mmcf/d Plant

DEE 11-03

15 mmcf/d

Gas Plant

DEE 5-8 10 mmcf/d

Montney Facility

December 2016

MARKET ACCESS ADVANTAGE

10

Exceptional Gas Marketing

Considerable production growth targets are achievable utilizing existing major infrastructure

Secured firm service agreement to access larger Chicago gas market for better pricing

Pricing has been significantly better than AECO

Secured firm service minimizing exposure to curtailments on the TCPL pipeline system

Delphi / Alliance

Full-path service to Chicago

December 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 natural gas and

crude oil prices

Consistent Hedge Performance Natural Gas Q4/16 Q1/17 Q2 - Q4/17 2018 2019

% Hedged 75% 65% 59% 30% 21%

Hedge Price (Cdn $/mmbtu) $4.54 $4.28 $4.21 $3.77 $3.89

Crude Oil Q4/16 Q1/17 Q2 - Q4/17 2018 2019

% Hedged 49% 73% 49% 16% 16%

Floor Price (WTI Cdn $/bbl) $76.44 $66.78 $66.67 $70.00 $70.00

Ceiling Price (WTI Cdn $/bbl) $85.00 $66.78 $66.67 $70.00 $70.00

11December 2016

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

138 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

MONTNEY GROWTH AT BIGSTONE

Bigstone Montney Liquids-Rich Gas Play Montney Production (boe/d)

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 accelerating with increasing yields

Montney Field Condensate Production (boe/d)

12

2012 2013 2014 2015 2016(F) 2017Target

68

65

4-5

Delphi Montney Wells Drilled

10-14

December 2016

CONSISTENT ECONOMIC RESERVE GROWTH

13

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

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)

28 wells drilled life-to-date (LTD)

Produced 7.2 million boes in 4.5 years

Generated $180 million in operating income

Cumulative capital of $325 million;

Including $40 million of infrastructure

costs

Significant Inventory for growth

Montney Development (2012 to Q3 2016)

2015 drilling program was focused on infill

locations;

19% PDP reserve growth

8 of 138 sections are fully developed

Only 30 undeveloped locations in 2P

reserves

2016 drilling program focused on moving west

16-9 Frac planned for late November

December 2016

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

14

80 93 106132 140

101

252

-

50

100

150

200

250

300

TypeWell

15-23 14-24 14-27 16-30Refrac

13-21

Fie

ld C

on

de

ns

ate

Yie

ld (

bb

ls/m

cf)

IP30 Montney Field Condensate

Yields

Frac innovation yielding

more condensate

Netbacks 1.2 to 1.8 times higherDEE 12-17

2013 Drill

IP30 CGR 62 bbl/mmcf

XTO 2015 Drill

CGR 260 bbl/mmcf

(based on public data)

DEE Type Well

IP30 CGR 98

bbl/mmcf

DEE 13-21

2015 Drill

IP30 CGR 252 bbl/mmcf

ATH 2015 Wells

IP30 CGR

158 to 242 bbl/mmcf

DEE 16-30 Refrac

IP30

CGR 101 bbl/mmcf

Most recent wells

December 2016

14-11

DELIVERING EXCEPTIONAL MARGIN GROWTH

15

Increased condensate yields and lowered cash costs

Q3 2016 compared to Q3 2015;

Condensate production increased 39%

Field netbacks (excluding hedging) increased 109%

December 2016

2016 Focus on Margin Growth Paid Off

Source: AltaCorp Capital

Operating Costs vs. Gas Weight

2016/2015 Q2 Operating Costs vs. Production Mix Relative Change

OUTSTANDING WELL PERFORMANCE

16

Well Count Sales Production Rate

Gasmmcf/d

FieldCondensate

bbl/dTotal

boe/d

CondensateYield

bbl/mmcf

IP30 22 4.7 450 1,420 95

IP90 20 4.2 331 1,203 79

IP180 20 3.6 250 988 70

IP270 18 3.2 194 849 61

IP365 15 2.8 166 754 58

At day 158 13-21 gas rate flat at 3mmcf/d

Condensate yield at 115 bbl/mmcf sales

December 2016

0

1,000

2,000

3,000

4,000

5,000 884816

33

20

94

59

26

47330

57

Top Decile for 3-Month

Production Rates

IP90 (mcf/d)

473 Wells of 724 Wells Drilled

DELPHI WELL COST IMPROVEMENTS

17

Delphi Well CostsDelphi Well Costs

IP90 Day Capital Efficiencies

Montney Capital Efficiencies

0

5,000

10,000

15,000

2012 2013 2014 2015 2016 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 five wells.

Record low drilling & completions cost of

$6.5 million achieved

Additional cost savings are being achieved;

3 - 4 wells per pad from 2 well pads

IP90 Capital Efficiencies:

Top decile efficiencies of $6,000 boe/d.

Achieved through cost reductions and

robust IP90 rates of 1,200 boe/d.

December 2016

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

18

Rich Type Well13-21 Yield 2.5x Type Well at 100 bbl/mmcf

Note: See Montney Economic Model Assumptions in the Forward Looking Statement

and Important Notes

DEE Type Well

December 2016

PRELIMINARY 2017 DRILLING PLANS

December 2016 1919

Filling infrastructure

Montney pay thickness

increasing to 150 meters;

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 138 sections

Accelerating Drilling West

Legend

Drilled

Drilling 2017 (Winter)

DEE activity planned for 2H

2016 and 2017

25 – 30 well inventory just in

this small area

• Up to 8 wells drilled this winter

• Approx. 5 to 6 wells funded under a joint program

• Remaining wells will be funded within cash flow

• Majority expected on production in Q2 / Q3 2017

WEST BIGSTONE EAST BIGSTONE

D3

D2

D1

B1

C

D1

C

D2

B1

2017 AND BEYOND – MAINTAINING KEY VALUES

20

Continued new well innovation; Significant infrastructure and processing

capacity in place

Letter of Intent in place with an existing industry partner to significantly

accelerate development and production growth

World Class Montney Asset

Operational Control

Land Inventory

Market Access

Performance

Considerable production growth targets are achievable utilizing existing

major infrastructure

No significant infrastructure capital required in this environment, low

operational costs

Operating efficiency gains lifting “unhedged” netbacks through 2019

2017 winter drilling program to double with a second rig

$20 million Partner carried cost

138 sections of Montney opportunity to continue developing

Partner to contribute $30 million in cash for working interest equalization

Secured firm service with Alliance to access Chicago gas market for

stronger pricing

December 2016

NEB, FirstEnergy, EIA, USGS

APPENDIX

December 2016 21

BIGSTONE MONTNEY OVERVIEW

22

Scalable and Repeatable

Liquids Rich

Large Resource in Place

Southeast corner of the unconventional Montney

trend

Developed with extended reach horizontal wells and

slickwater-fracing

Material capital cost advantage

Continuous hydrocarbon system top to bottom

Nearby deltaic sediment supply

Relatively high permeability with a fine sand/silt

reservoir

Relatively high porosity ranging from 4% to 12%

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

December 2016

DELPHI / ALLIANCE FIRM TRANSPORTATION SERVICE

23

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

Q3 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.

December 2016

COMMODITY PRICES: MANAGING VOLATILITY

24

Volatility creates

hedging

opportunities

CDN/US FX

NYMEX Contract Pricing

GA

S U

S$

/MM

BT

U

CR

UD

E U

S$

/BB

L

Natural gas prices were historically correlated to Crude prices

NYMEX NatGas vs. Crude Historical Settlement Pricing

Commodity price volatility creates 2

to 4 year hedging cycles

December 2016

HEDGES PROTECTING CASH FLOW

25

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) $2.51 $2.52 $2.46

Natural Gas (US) Jul – Dec 2016 Jan – Mar 2017 Apr – Dec 2017 2018 2019Volume (mmbtu/d) 22.6 19.1 17.0 10.0 7.0% Hedged (1) 68% 58% 52% 30% 21%Hedge Price (US $/mmbtu) $3.61 $3.24 $3.20 $2.87 $2.92Strip Price (US $/mmbtu) $2.63 $2.84 $2.92 $2.90 $2.88% Hedged in Cdn $ (3) 100% 100% 100% 100% 100%Hedge Price (Cdn $/mmbtu) (4) $4.61 $4.31 $4.24 $3.77 $3.89

Crude Oil Jul – Dec 2016 Jan – Mar 2017 Apr – Dec 2017 2018 2019Volume (bbls/d) 900 1,350 900 300 300% Hedged (1) 49% 73% 49% 16% 16%Floor Price (WTI Cdn $/bbl) $76.44 $66.78 $66.67 $70.00 $70.00Ceiling Price (WTI Cdn $/bbl) (5) $85.00 $66.78 $66.67 $70.00 $70.00Strip Price (WTI Cdn $/bbl) $59.90 $62.77 $65.72 $67.82 $69.23

(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(6) Strip pricing as of November 8, 2016

December 2016

INDIVIDUAL MONTNEY WELL DATA

26

• 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

December 2016

LIQUIDS-RICH MONTNEY STUDY

ELMWORTH TO BIGSTONE

27

Elmworth

Wapiti

Kakwa

Delphi

Bigstone

Large Data Set

473 Montney wells with IP90 of

724 wells drilled to YE2015

Source of Data: geoSCOUT

27

Company 6

Company 7

Delphi

Company 3

Company 4

Company 1

Company 2

Company 8

Company 5

Other

December 2016

28

0

20

40

60

80

100

120

140

160

180

200

2008 2009 2010 2011 2012 2013 2014 2015

Producing* Wells by Rig Release DateTotal Wells (with IP90): 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

28


ELMWORTH TO BIGSTONE

December 2016


PRODUCTION BY OPERATOR (GAS IP’S ONLY)

29

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

29December 2016

0

500

1,000

1,500

2,000

2,500

3,000

Average Horizontal Length (m)


EVOLUTION OF DEPTH & HORIZONTAL LENGTH

30

2,000

2,500

3,000

3,500

4,000

4,500

5,000

5,500

6,000

2008 2009 2010 2011 2012 2013 2014 2015

Average Measured Depth (m)

920 42

61

0

500

1,000

1,500

2,000

2,500

3,000

2008 2009 2010 2011 2012 2013 2014 2015


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

30December 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

31

0

20

40

60

80

100

120

140

160

180

200

2008 2009 2010 2011 2012 2013 2014 2015

Average Frac Spacing (m)

Delphi Avg (97m)

2

9

19 40

60

100

176

592

6

16

39

51

166 5085

Delphi Avg (29 stages)

31

0

5

10

15

20

25

30

35

Average Number of Stages per well

0

20

40

60

80

100

120

140

Average Frac Spacing (m)

December 2016

32

0

20

40

60

80

100

120

140

160

180

200

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

Number of Wells

0

1,000

2,000

3,000

4,000

5,000

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


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

80

149 9079

21

28

16

76133 75

70 20 21

12

66

93 48 4711

8

32


EVOLUTION OF FRAC DENSITY

December 2016


EVOLUTION OF PROPPANT PLACED

33

0

1,000

2,000

3,000

4,000

5,000

6,000

0.00

0.20

0.40

0.60

0.80

1.00

1.20

1.40

2008 2009 2010 2011 2012 2013 2014 2015

Proppant Placed

tonnes t/m

0

1,000

2,000

3,000

4,000

5,000

0.00 - 0.25 0.26 - 0.50 0.51 - 0.75 0.76 - 1.00 1.01 - 1.25 1.26 - 1.50 1.51 +

IP-90 (mcfd raw)

t/m

0

1,000

2,000

3,000

4,000

5,000

0.00 - 0.25 0.26 - 0.50 0.51 - 0.75 0.76 - 1.00 1.01 - 1.25 1.26 - 1.50 1.51 +

IP-180 (mcfd raw)

t/m

25

43

74128

77 6052

25

38

119

70

68

51 34

2 8 19 42 61 100 175 59

Delphi Avg (0.76 t/m)

33December 2016


EVOLUTION OF FLUID PUMPED

34

0

2,000

4,000

6,000

8,000

10,000

12,000

14,000

16,000

18,000

20,000

0.00

1.00

2.00

3.00

4.00

5.00

2008 2009 2010 2011 2012 2013 2014 2015

Fluid Pumped

m3/well m3/m

0

1,000

2,000

3,000

4,000

5,000

0.0 - 2.0 2.1 - 4.0 4.1 - 6.0 6.1 - 8.0 8.0+

IP-90 (mcfd raw)

0

1,000

2,000

3,000

4,000

5,000

0.0 - 2.0 2.1 - 4.0 4.1 - 6.0 6.1 - 8.0 8.0+

IP-180 (mcfd raw)

m3/m m3/m

110

19364

5445

107

163 57 49 36

2 8 19 42 61 100 175 59

Delphi Avg (3.65 m3/m)

34December 2016


FRAC TYPES

35

228

176

107

45

0

50

100

150

200

250

Frac by Fluid Type

35

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

Frac by Fluid Type(mcfd raw)

slickwater water oil surfactant

December 2016

36

0

10

20

30

40

50

60

Average Drilling Days

57 17 31 21 25 94 47 61 19 89 36 497

36


DRILLING EFFICIENCY

0

500

1,000

1,500

2,000

2,500

3,000


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.

December 2016

300, 500 – 4th Avenue SW

Calgary, Alberta T2P 2V6

P (403) 265-6171

F (403) 265-6207

[email protected]

www.delphienergy.ca

December 2016 37

mailto:[email protected]

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