CORPORATE PRESENTATION
APRIL 2016
CORPORATE PRESENTATION APRIL 2016 FORWARD-LOOKING STATEMENTS The - - PowerPoint PPT Presentation
CORPORATE PRESENTATION APRIL 2016 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
APRIL 2016
The presentation contains forward-looking statements and forward-looking information within the meaning of applicable Canadian securities laws. These statements relate to future events
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
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
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
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 April 2016
3
April 2016
4 April 2016
2016 Priorities Through This Structural Reset
5
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
Net Debt Dec. 31, 2015 $122 million Credit Dec 31, 2015 $146.5 million
April 2016
Montney liquids-rich resource development
Wapiti
Tower Creek
Bigstone Hythe
Dawson Creek Grande Prairie Hythe and Wapiti sold in 2015
April 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
7
Resthaven East Bigstone Fir South Bigstone West Bigstone
Exxon Chevron ATH DEE Exxon ECA Exxon Exxon Conoco
sections since 2010
the liquids-rich play
East Bigstone
Continue to pursue additional Montney acquisition/farm-in
Bigstone
April 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
Bigstone
compression facilities
processing plant
2015
and project economics
April 2016
9
Delphi 100% owned Water Disposal Facility
injection in excess of 4,000 bbls/d
required
April 2016
10 April 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.
11 April 2016
to 3,000 m
performance
slickwater frac design
focused on low-risk high productivity infill drilling
laterals per section to 5 or 6
beyond with ultra-high condensate yields
CLT 10 wells NAL 2 wells 3-26 12-17 ATH 5 wells DEI 3 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
DEE activity planned for 2H 2016 and 2017
12
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
April 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
32 56 55 55 56 10 13 11 10 10 11 13 12 13 13 14 14 17 19 18
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)
13
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
well have trended down by 26 percent from $11.0 million in 2012
compared to $10.4 in 2014
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
Well costs down 36 percent
April 2016
14
29% 1% 31% 47% PDP PDNP PUD PA
Montney Development (2012 to 2015)
19 percent growth in PDP reserves in 2015
April 2016
15,108 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
15 April 2016
Number IP30 IP30 IP30 IP90 IP180 IP270 IP365 IP 2yr HZ Length
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 1,172 948 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 1,204 662 291 15-23 #25 2,865 waiting on completion 1,444 456 141 1,206 989 870 766 660 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.
Conventional Fracs (original completion technique) Slickwater Fracs (new completion technique) Average Wells #5 through #24
from 1.0 years previously:
Slow-back experiment
16 April 2016
$10.00 $15.00 $20.00 $25.00 $30.00 $35.00 $40.00 $45.00 50 100 150 200 250 300
Revenue ($/boe) Field Condensate Yield (bbl/mmcf sales)
15-30 Life-to-Date 14-27 IP30 Type Well 15-21 Life-to-Date
2016 Price Forecast
AECO Nat Gas: Cdn$1.82/mcf NYMEX Nat Gas: US$2.00/mmbtu WTI: US$38.00/bbl Condensate: Cdn$47.00/bbl NGLs: Cdn$16.50/bbl
13-21 IP30 Recycle Ratio = 1.8 14-24 IP30 $10.00/boe increase in revenue (before hedges) $7.75/boe hedging gain forecast in 2016
higher condensate yields
Delphi's in-the-money hedges
a 1.8 PDP recycle ratio on unhedged netbacks
$10.00 $15.00 $20.00 $25.00 $30.00 $35.00 $40.00 $45.00 50 100 150 200 250 300
Revenue ($/boe) Field Condensate Yield (bbl/mmcf sales)
15-30 Life-to-Date 14-27 IP30 Type Well 15-21 Life-to-Date Recycle Ratio = 1.5
2017 Strip Price
AECO Nat Gas: Cdn$2.47/mcf NYMEX Nat Gas: US$2.50/mmbtu WTI: US$45.00/bbl Condensate: Cdn$54.50/bbl NGLs: Cdn$16.50/bbl 13-21 IP30 Recycle Ratio = 2.3 14-24 IP30 $12.00/boe increase in revenue (before hedges) $2.10/boe hedging gain forecast in 2017 17 April 2016
2016 2016
continue to generate robust new well revenue and netbacks even with less hedging than 2016
a 2.3 PDP recycle ratio in 2017
Conoco Completed in 2013 Conoco Completed in 1H 2014 Conoco Completed in 2015 Delphi 9-4 Well Conventional Gelled Oil Frac in 2012
18 April 2016
Moving West
moving from east to west
per section spacing
sour
infrastructure in place
2 to 4 times greater than East Bigstone
innovated
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
19 April 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 = $10,000 boe/d
Delphi Energy - Bigstone Montney Two Section Horizontal Type Well 30 to 40 stage Slickwater Completion
Strip Pricing(1) GLJ Jan. 2016 Pricing(2) Capital Target Capital (D,C,E&TI) MM$ $7.0 Initial Production (day 1) Gas mmcf/d raw 7.0 Initial Field Condensate bbl/mmcf sales 80 Plant C3+ NGL Recovery bbl/mmcf sales 39 Initial Production (IP30 - first 30 day average) Gas mmcf/d raw 6.4 Total Liquids (C3+)(3,4) bbl/mmcf sales 120 Total Liquids (C3+)(3,4) bbl/d 670 Total IP30 boe/d 1,600 Total Liquids IP30 (C3+)(3,4) bbl/d 670 Reserves (sales) Gas bcf 4.6 Liquids (C3+)(3,4) mmbbl 0.4 Total mmboe 1.2 Economics/Metrics Payout yrs 2.1 1.5 IRR % 42% 75% NPV 10 MM$ $4.9 $9.9 F&D $/boe $6.02 $6.02
(1) 2016 Prices: Henry Hub $2.26/mmbtu US, $2.94/mmbtu CDN; WTI $43.63/bbl USD; C5 $56.77/bbl CDN (2) 2016 Prices: Henry Hub $2.60/mmbtu US, $3.59/mmbtu CDN; WTI $44.00/bbl USD; C5 $60.79/bbl CDN (3) Stabilized Field Condensate beyond first month is 46 bbl/mmcf sales (4) C3: Propane, C4: Butane, C5: Pentane (5) Type Well Reserves and Production performance are internal management estimates and may not reflect the actual performance of the wells. The estimates are used for illustrative purposes and internal corporate planning. Half cycle economics include well costs to drill, complete, equip and tie-in. No costs for land, central facilities, main gathering infrastructure, corporate costs, etc. are included.
Initial Production Assumptions: Gas 4.0 mmcf/d raw Field Condensate (1st month) 200 bbl/mmcf raw Gas Reserves 4.0 bcf raw IRR Payout NPV10 raw gas sales gas (years) (MM$) 120 139 87% 1.3 $10.2 100 116 68% 1.6 $8.2 79 91 50% 1.9 $6.0 after 1st month bbl/mmcf
Ultra Rich Economic Sensitivities
Field Condensate Yield
March 2016 20
12-16-60-23W5 Hz Gething Drilled 2012 789 m Hz length 10 stage ball drop, 30T N2 foam frac “Concept Well” to prove playBigstone Gething Land
TOU’s Leland Falher >45 Bcf CummBigstone 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
productive
liquids Delphi infrastructure in place with low OPEX
White Specks
several areas
Tight Sand Exploitation: The Past and The Present
regional sand high perm interval
good well the new paradigm great wellDelphi has drilled 25 vertical Gething wells with 98% success since 2005 HZ multi-stage fracing technology is the next generation of development
21 April 2016
Volatility creates hedging opportunities
CONSISTENT AND PROVEN RISK MANAGEMENT PROGRAM
Event driven hedging strategy with a long term view of a relatively balanced supply/demand market with “events”:
provides revenue and cash flow certainty
spike events affecting the futures curve
in place over a 12 to 48 month period
program has:
event cycles
April 2016 22
$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
$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
23
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) $1.75 $2.68 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) $2.26 $2.77 $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) $51.55
(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
April 2016
24
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
April 2016
25 April 2016
In the context of 2016 forecast pricing:
(US$38.00 WTI and US$2.00 NYMEX)
2016 CAPEX / CF MATRIX Number of 2016 Exit Rate US$ 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
26 April 2016
Levers Still to be Pulled in an “Oil Lower for Much Longer” Scenario:
27
April 2016
29 April 2016
Elmworth Wapiti Kakwa Delphi Bigstone
Source of Data: geoSCOUT
Large data set 488 Montney wells on production
30 April 2016
Drilling remains active with 106 Montney wells rig released YTD 2015
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
500 1,000 1,500 2,000 2,500 3,000 2008 2009 2010 2011 2012 2013 2014 2015
Average Horizontal Length (m)
31 April 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)
5 10 15 20 25 30 2008 2009 2010 2011 2012 2013 2014 2015
Average Number of Frac Stages/Well
32 April 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
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
33 April 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
300, 500 – 4th Avenue SW Calgary, Alberta T2P 2V6 P (403) 265-6171 F (403) 265-6207 info@delphienergy.ca www.delphienergy.ca