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DEE
2014
NOVEMBER 2014 CORPORATE PRESENTATION
FORWARD-LOOKING STATEMENTS
2
DEE
The presentation contains forward-looking statements and forward-looking information within the meaning of applicable Canadian securities laws. These statements relate to future
events or the Company’s future performance and are based upon the Company’s internal assumptions and expectations. All statements other than statements of present or historical
fact are forward-looking statements. Forward-looking statements are often, but not always, identified by the use of any of the words “expect”, “anticipate”, “continue”, “estimate”,
“may”, “will”, “should”, “believe”, "intends”, “forecast”, “plans”, “guidance”, “budget” and similar expressions. More particularly and without limitation, this presentation contains
forward-looking statements and information relating to petroleum and natural gas production estimates and weighting, projected crude oil and natural gas prices, future exchange
rates, expectations as to royalty rates, expectations as to transportation and operating costs, expectations as to general and administrative costs and interest expense, expectations as
to capital expenditures and net debt, planned capital spending, future liquidity and Delphi’s ability to fund ongoing capital requirements through operating cash flows and its credit
facilities, supply and demand fundamentals for oil and gas commodities, timing and success of development and exploitation activities, cash availability for the financing of capital
expenditures, access to third-party infrastructure, treatment under governmental regulatory regimes and tax laws and future environmental regulations. Furthermore, statements
relating to “reserves” are deemed to be forward-looking statements as they involve the implied assessment, based on certain estimates and assumptions that the reserves described can
be profitable in the future. The forward-looking statements and information contained in this presentation are based on certain key expectations and assumptions made by Delphi. The
following are certain material assumptions on which the forward-looking statements and information contained in this presentation are based: the stability of the global and national
economic environment, the stability of and commercial acceptability of tax, royalty and regulatory regimes applicable to Delphi, exploitation and development activities being
consistent with management’s expectations, production levels of Delphi being consistent with management’s expectations, the absence of significant project delays, the stability of oil
and gas prices, the absence of significant fluctuations in foreign exchange rates and interest rates, the stability of costs of oil and gas development and production in Western Canada,
including operating costs, the timing and size of development plans and capital expenditures, availability of third party infrastructure for transportation, processing or marketing of oil
and natural gas volumes, prices and availability of oilfield services and equipment being consistent with management’s expectations, the availability of, and competition for, among
other things, pipeline capacity, skilled personnel and drilling and related services and equipment, results of development and exploitation activities that are consistent with
management’s expectations, weather affecting Delphi’s ability to develop and produce as expected, contracted parties providing goods and services on the agreed timeframes, Delphi’s
ability to manage environmental risks and hazards and the cost of complying with environmental regulations, the accuracy of operating cost estimates, the accurate estimation of oil
and gas reserves, future exploitation, development and production results and Delphi’s ability to market oil and natural gas successfully to current and new customers. Additionally,
estimates as to expected average annual production rates assume that no unexpected outages occur in the infrastructure that the Company relies on to produce its wells, that existing
wells continue to meet production expectations and any future wells scheduled to come on in the coming year meet timing and production expectations. Commodity prices used in the
determination of forecast revenues are based upon general economic conditions, commodity supply and demand forecasts and publicly available price forecasts. The Company
continually monitors its forecast assumptions to ensure the stakeholders are informed of material variances from previously communicated expectations. Financial outlook information
contained in this presentation about prospective results of operations, financial position or cash flows is based on assumptions about future events, including economic conditions and
proposed courses of action, based on management’s assessment of the relevant information currently available. Readers are cautioned that such financial outlook information
contained in this presentation should not be used for purposes other than for which it is disclosed. Although the Company believes that the expectations reflected in such forwardlooking 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.
FOCUS ON CONDENSATE-RICH BIGSTONE MONTNEY
3
DEE
Bigstone Montney the driver of significant growth
Built a 7,700 boe/d asset
with a current run-rate cash
flow of $75 million on net
capital of $70 million
138 gross sections with
a drilling inventory of
4 to 6 laterals per
section
Payout achieved on 3 wells
(6 to 14 months) with
production rates at payout
of 500 -700 boe/d
Production
Q2 2014 Production (32% Oil/NGLs)
Q4 2013 Production (28% Oil/NGLs)
Reserves
December 31, 2013 GLJ Proved plus Probable
December 31, 2012 GLJ Proved plus Probable
Balance Sheet
Net Debt June 30, 2014
Current Credit Capacity (Senior and Subordinated)
Shares Outstanding
Market Capitalization
Enterprise Value
10,397 boe/d
8,988 boe/d
61.7 mmboe
43.0 mmboe
$157.0 million
$190.0 million
155.4 million
$333 million
$498 million
BIGSTONE MONTNEY: PLAY EVOLUTION
•
•
•
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 6 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
Drilling 8 HZ wells in 2014
• Further delineation of the East
Bigstone area
• Further evolution of the
slickwater frac design with
tweaks to sand concentration,
frac water volumes and number
of frac stages in the lateral
ATH
2 wells
13-30
To KA Sour
Plant
15-30
16-30
10-27
14-23
16-23
4
DEE
15-24
DEI
3 wells
15-21
8-21
16-15
2-7
15-10
5-2
2-1
NAL
2 wells
CLT
10 wells
3-26
12-17
DEE 7-11
Sour Montney Facility
Expanded to 45 mmcf/d in Q1
2014
BIGSTONE MONTNEY: PRODUCTION GROWTH
2014 YTD Production 10,050 boe/d
5
DEE
Montney Production Ramps Up in 2014
• Eleven fold increase in Montney production from 700 boe/d
in Feb 2013 to 7,700 boe/d in Sept 2014
Hythe
Bigstone Cretaceous
• Montney production represents 70% of corporate production
in Sept 2014
Bigstone Montney
Wapiti
• Average corporate production for 2014 forecast to grow by
24% over 2013
Tower Creek
Other
• 2014 exit production forecast to be 11,500 -12,000 boe/d
12,000
Gas(boe/d)
Oil(bbls/d)
Bigstone Montney
Other
10,000 – 10,500
10,000
10,000
8,870
8,000
12,000
NGLs(bbls/d)
8,086
8,276
8,241
8,000
6,000
6,000
4,000
4,000
2,000
2,000
-
2010
2011
2012
2013
2014 F
Q412 Q113 Q213 Q313 Q413 Q114 Q214 Q314F Q414F 14ExitF
BIGSTONE MONTNEY: IMPROVING NETBACKS
Liquids Yield (bbls/mmcf)
Field Condensate
Plant Condensate
Butane
Cash Netbacks Increasing with Montney Growth
Propane
120
Ethane
Montney
100
80
8
9
7
9
40
20
13
13
6
12
7
10
60
16
10
12
14
Corporate
64
56
2012
2013
• Montney average liquids yield in 2014 YTD of 98
bbls/mmcf (71% field and plant condensate)
• Montney field netback significantly better than
corporate average due to much greater highvalue liquids content of production
• Average gas prices better in 2014 over 2013
• Lower royalty rate for Montney under royalty
holiday program and NGDDP royalty credits
35
19
1H 2014
2013
1H 2014
Cash Netback ($/boe)
Cash Flow ($ millions)
$35.00
$30.00
$21.0
Hedging
Netback from Production
$15.0
$20.00
$34.33
$15.00
$23.93
$10.00
$14.35
$17.98
$8.92
$12.80
$20.69
First Half 2014
$12.0
$9.0
2010
2011
2012
2013 1H 2014
Other Montney
$14.7
$6.0
$3.0
$0.00
-$5.00
66% growth in cash flow
expected over 2013
$18.0
$25.00
$5.00
6
DEE
$9.4
$8.4
Q1 13
Q2 13
$6.3
$10.0
$11.4
$20.4
$Q4 12
Q3 13
Q4 13
Q1 14
Q2 14
BIGSTONE MONTNEY:
Montney Development
Dec. 31, 2013 Categories
24%
41%
3%
32%
•
271% growth in PDP reserves over 2012
•
Increase in 2P value to $242.7 million and 2P Montney reserves to 33.1 mmboe
PDP
Delphi Capital Efficiencies (proved plus probable)
PDNP
•
2013 FD&A - $9.43 per boe, 3 year avg FD&A - $11.54 per boe
PUD
•
FDC of $322 million funded with cash flow
PA
Delphi 2013 Net Asset Value
•
$3.41 per share, 58 percent increase from YE 2012
61,662
34,521
Other
46%
19,267
36,142
25,074
92%
307
74%
23,796
54%
2010 – 2013
 78% Increase in reserves
 31% Increase in reserves per share
306
Montney
43,063
11,800
22,721
Proved Plus Probable Reserves
25,520
Probable (mboe)
Proved (mboe)
Reserves /1,000 shares
40,182
15,108
RESERVES
7
DEE
281
100%
402
26%
8%
2010
2011
2012
2013
2010
2011
2012
2013
BIGSTONE MONTNEY:
250
SELF SUSTAINING
8
DEE
($ millions)
ACTUALS
PROFORMA
200
Quick Payback period and High PI ratios.
150
Expected end of 2015 run-rate annual production of
3.5 million boe, requiring 3-4 wells per annum to
maintain production, resulting in annual run-rate free
cash of $50-60 million.
CAPITAL EQUALS CASH FLOW
100
50
CAPITAL LESS THAN CASH FLOW
0
Cumulative Capital
Cumulative Cash Flow
Net Cumulative Capital
9
DEE
BIGSTONE MONTNEY: ECONOMIC MODEL
Two Section Montney Horizontal w/ 30 stage Slickwater Hybrid Completion
Revised Type Well (1)
Capital
Total
MM$
$9.2
Initial Production (day 1)
Gas
Initial Field Condensate
Plant C3+ NGL Recovery
mmcf/d raw
bbl/mmcf sales
bbl/mmcf sales
7.0
79
40
Initial Production (IP30 - first 30 day average)
Gas
mmcf/d raw
Total Liquids (C3+)
bbl/mmcf sales
Total Liquids (C3+)
bbl/d
6.4
119
677
Economics/Metrics
Payout
ROR
NPV 10
PI
F&D
Netback (12 mo ave)
Recycle Ratio
bcf
mmbbl
mmboe
yrs
%
MM$
$/boe
$/boe
1,629
677
4.7
0.4
1.2
0.9
140%
$18.5
3.0
$7.75
$39
5.1
(1) Economics ran using GLJ January 1, 2014 price forecast
(2) Stabilized Field Condensate beyond first month is 45 bbl/mmcf sales
(3) Type Well Reserves and Production performance are intenal management
estimates and may not reflect the actual performance of the wells. The estimates
are used for illustartive purposes and internal corporate planning
(4) C3: Propane, C4: Butane, C5: Pentane
Performance matching type curve
3,000
12
2,500
10
2,000
8
1,500
6
1,000
4
500
2
0
0
0
100
200
300
Producing Days
400
500
Producing Well Count
Reserves (sales)
Gas
Liquids (C3+)(2)
Total
boe/d
bbl/d
Production
boe/d & bbls/d
Total IP30
Total Liquids IP30 (C3+)
BIGSTONE MONTNEY:
Slickwater Wells Achieving Payout
• 3 wells to date
• Payout achieved on approximately
20% of well EUR
• Average production at payout of 500700 boe/d
• Cash operating income after payout
funding continuous drilling program
WELL PAYOUTS
10
DEE
BIGSTONE MONTNEY:
Slickwater Wells Achieving Payout
• 2-3 more wells to achieve payout by
December 31, 2014
• 6 of the first 9 Slickwater 30 stage
wells will have achieved payout in 6
to 18 months
• Leading to self sustainability of
Bigstone Montney Program
WELL PAYOUTS
11
DEE
BIGSTONE MONTNEY: PRODUCTION PERFORMANCE
3,000
12
Typecurve Total Sales (boe/d)
Typecurve Field Condensate (boe/d)
Average 30 Stage HZ Total Sales
Average 30 Stage HZ Field Condensate
10
Production volumes of 500 to 700 boe/d at
payout generate significant cash operating
income to fund future drilling
2,000
8
1,500
6
Wells Pay Out
1,000
4
500
2
0
0
0
50
100
150
200
250
Producing Days
300
350
400
450
500
Producing Well Count
2,500
Production
boe/d & bbls/d
12
DEE
BIGSTONE MONTNEY: WELL PERFORMANCE
13
DEE
Initial Production (IP) Rate Well Performance (1)
HZ Length
Well(2)
Number
IP30
IP30
IP30
IP90
IP180
Total Sales
of Fracs
Total Sales
FCond Rate
Total NGL
Total Sales
Total Sales
on Day 180
(boe/d)
(bbls/d)
(bbl/mmcf)
(boe/d)
(boe/d)
(boe/d)
1,099
273
104
798
558
259
Yield
(metres)
Payout
Monthly
(months)
COI (4) at
Payout
(% of EUR)
($000's)
14/23%
>$500
Conventional Fracs (original completion technique)
16-30
#1
2,760
20
05-02
#2
3,005
20
969
170
80
683
479
250
14-23
#3
2,238
20
1,570
223
70
939
635
291
1,424
20
991
194
86
842
660
421
Slickwater Fracs (new completion technique)
15-10
#4
12-17
S.BS Expl
Revised Type Well
(3)
1,848
26
865
199
102
2,400 – 3,000
30
1,629
449
119
1,306
1,083
746
10-27
#5
2,407
30
1,815
582
133
1,667
1,364
928
16-23
#6
2,809
30
1,781
465
108
1,502
1,235
842
15-24
#7
2,328
30
1,387
454
136
1,221
1,059
824
9/19%
>$700
15-30
#8
3,014
30
2,076
566
113
1,837
1,517
1,065
6/18%
>$1,000
15-21
#9
2,886
30
1,293
499
170
1,053
875
604
13-30
#10
2,593
30
2,075
655
136
1,750
1,457
1,146
02-01
#11
2,807
30
634
209
142
498
02-07
#12
2,702
30
1,116
327
126
08-21
#13
2,692
30
978
280
123
16-15
#14
2,949
30
1,503
298
91
03-26
#15
2,601
13-23
#16
2,161
870
30
waiting on completion
(1) Average production calculated on operating days, excludes non-producing days. Includes estimated NGL gas plant recoveries.
(2) Slickw ater frac w ells numbered chronologically.
(3) Initial Exploration Well on Delphi's South Bigstone Lands.
(4) Cash operating income – revenue less royalties, op costs and transportation.
•
•
New wells 3X better:
At Payout:
• 500-700 boe/d
• Significant free cash flow
BIGSTONE MONTNEY: PRODUCTION TRENDS
14
DEE
2,500
Value creation remains robust
•
•
•
•
Type Well NPV = $18.5 million
IRR = 140%
PI = 3.0
Payouts = 6 to 16 months
Production (boe/d)
2,000
1,500
1,000
500
0
IP30
IP60
IP90
IP120
IP150
IP180
IP270
Convergence of rates over time
$18.5 million
NPV (PV10)
Lower intial gas rate:
Decline profile less than type curve
C5+ yields higher than type curve
• Lower initial gas rate = lower decline
Condensate Yields
Higher initial gas rate:
Decline profile and C5+ yields
similar to type curve
7 mmcf/d
Initial Gas Rate
• Lower initial gas rate = higher yield
• Yields stabilize within first 3 months
IP365
PRODUCTION:
15
DEE
CUMULATIVE REVENUE
Cumulative Revenue
24,000
10-27-60-23W5
13-30-60-22W5
12-17-59-22W5
22,000
16-23-60-23W5
02-01-60-23W5
03-26-59-23W5
15-24-60-23W5
02-07-60-22W5
Revised Type Well
15-30-60-22W5
08-21-60-22W5
First 3 Wells
15-21-60-23W5
16-15-60-23W5
20,000
Pricing Assumptions
$3.68 Gas Price - $/mcf
$37.88 C3 Price - $/bbl
$72.67 C4 Price - $/bbl
$99.66 C5 Price - $/bbl
CUMULATIVE REVENUE (M$)
18,000
16,000
14,000
12,000
10,000
8,000
New wells generating up to 3 times more revenue:
6,000
Higher condensate yields
Lower decline profiles
Faster payouts
Greater NPV’s and ROR
4,000
2,000
All shut in days have been removed
0
0
50
100
150
200
250
300
350
FLOWING DAYS
400
450
500
550
600
BIGSTONE MONTNEY: ASSEMBLED 138 SECTIONS
16
DEE
East Bigstone: 78 sections
West Bigstone: 27 sections
•
26.3 sections of Cretaceous added Sept/14
•
includes strategic infrastructure
•
The Bigstone Montney is a condensate-rich / NGL play
• Condensate yields of 40 to 130 bbls/mmcf
• Shallow cut C3+ NGL yields of 40 – 45 bbls/mmcf
• Deep cut extraction can yield another 40 bbls/mmcf
•
More than
•
Average land cost of $376,000 per section
200
two mile HZ locations for full development
•
Held 4 sections of legacy Montney rights
below existing DEE production
•
Added 12 sections of Montney rights through
acquisition and farm-in in 2011/12
•
Farm-in added an additional 2.5 sections
(75% WI)
•
Acquisition added 30 gross (89% WI)
•
Farm-in adds 10 sections (100% WI)
•
Recent Crown sales and acquisitions add 11
sections
•
Recent acquisition of 8.0 sections (3.5 net)
added Sept/14
South Bigstone: 33 sections
Farm-in added an additional 32.5 sections (75% WI)
Includes Nordegg/Montney rights
BIGSTONE MONTNEY:
17
DEE
DEVELOPMENT
East Bigstone
Development/Manufacturing Mode
+100 Locations
East Bigstone
20 producing wells
West Bigstone
Upper Montney
+100 Locations
Area of Focus
Fir
10 producing wells
West Bigstone
1 DEE producing well
2 Industry wells completed
South Bigstone
16 DEE Producing
Montney Horizontals
Lower Montney
Exploration
BIGSTONE MONTNEY: A GREAT PIECE OF REAL ESTATE
•
Montney land position has grown to 138 gross (116.5 net)
sections since 2010
•
Delphi one of the largest Montney landowners on map sheet
•
Delphi is a leader in the technical evolution of the liquidsrich play
•
Development drilling inventory of +100 two mile HZ wells at
East Bigstone
•
•
Exxon
18
DEE
Chevron
Exxon
ECA
West Bigstone will require +100 to develop
• Industry is de-risking area
East Bigstone
Continue to consolidate land and infrastructure:
West Bigstone
• 8.0 gross (3.5 net) sections of Montney acquired at
East Bigstone
• 26.3 gross (19.3 net) sections of Cretaceous rights
with production; includes plant and P/L infrastructure
Exxon
• Cretaceous rights now total 87.5 gross sections
ATH
DEE
Fir
Exxon
Exxon
Conoco
Resthaven
South Bigstone
BIGSTONE MONTNEY: 2015 DRILLING PROGRAM
19
DEE
Area of 5 year / 70 well
Development plan
10 8
17
East Bigstone
6
16
9
7
13
5
2015 Drilling Plans Include:
• 8 HZ wells at East Bigstone
• 4 wells drilled in first half
• 4 wells drilled in second half
• Primarily focused on capital efficiencies:
• Pad drilling
• Utilizing existing pipelines
• Filling existing facilities to capacity
1
14
3
4
12
2
11
15
12-17
2015
2014
2013
2012
BIGSTONE MONTNEY: STRATEGIC INFRASTRUCTURE
Rge25W5
•
•
Rge22
Rge23
Rge19
Delphi owns significant existing infrastructure in
the Bigstone area
Rge18
KA SemCAMS
Sour processing capacity at SemCAMS K3
•
•
•
•
Rge24
20
DEE
Twp 61
Lower fee structure by $2 to $3 per boe
Higher plant NGL recoveries
Greater long-term capacity available to meet
Delphi’s growth plans
Pursuing plans to further optimize netbacks and
project economics
Twp 60
Delphi 7-11
Future DEE Amine
Plant (2016)
TLM BWGP
TCPL
Alliance
K3 SemCAMS
TCPL
Alliance
CFGGS Tie-in option to
TLM Edson Plant
for acid gas
Twp 58
Delphi Montney production switched
to SemCAMS K3 September/14
Saturn Deep Cut
TCPL
WEST BIGSTONE MONTNEY:
West Bigstone Montney:
• 27 sections (100% WI)
• Upper and middle Montney thicken
• Natural gas is sweet to marginally sour
• Condensate and NGL yields appear
greater than East Bigstone
• Slickwater “frac design” being perfected with
industry active in the area
21
DEE
DE-RISKING
Delphi 9-4 Well
Conventional
Gelled Oil Frac
in 2012
TCPL
Exxon License
West Bigstone $9.3 million acquisition:
• Cretaceous Gething sweet natural gas
• 430 boe/d and 1.5 million boes (PDP)
• 40 bbls/mmcf NGL’s
• 26.3 gross sections (73% WI)
• 15 mmcf/d gas plant and approx 40
kilometres of pipeline infrastructure
Conoco Completed
in 1H 2014
Conoco
Completed in 2013
Conoco
Licensed in 2H 2014
LOOKING AT THE FUTURE: 5 YEAR OUTLOOK
22
DEE
Bigstone Montney will be the driver of significant future growth
Major Themes:
•
Maximize value creation for the shareholder
•
•
•
Maintain “operational excellence” in executing our field operations
•
•
•
Big expensive wells require critical attention to detail at all levels
Economics are weighted to operational success not risky cost saving shortcuts
• The human experience factor takes care of low-risk time-cost savings
Increase financial flexibility over next 12 – 18 months
•
•
Focus on per share growth
Efficient use of incremental capital sources beyond cash flow
• Cost of capital alternatives is a key driver to going faster
• Debt / GORR Arrangement / Asset Dispositions / Equity
Focus on growth of production / Cash flow / PDP reserve value
• Targeting net debt to cash flow of 1.5 in 2015
• Maintain debt level relatively flat
• Significant growth in lending value beyond 2015
Continue to de-risk West Bigstone to maintain long term drilling inventory
• Targeting to be drill ready for the winter season of 2015-16
5 YEAR OUTLOOK:
300
FINANCIAL FLEXIBILITY
($ millions)
(Net Debt/FFO)
Total Debt
23
DEE
3.0
Net Debt/FFO
250
2.5
200
2.0
Target Net Debt/FFO – 1.5X
150
1.5
100
1.0
Net Debt/FFO
Target of 1.5 times
achieved in 2015
50
0.5
0
0.0
2013
2014
2015
2016
Debt capacity assumes $16,000 per flowing boe
2017
2018
5 YEAR OUTLOOK: 70 WELL MONTNEY PROGRAM
Corporate
250
200
Maintenance
Montney
# Wells
($ millions)
(# Wells)
$770 million (70 well) Montney
capital expenditure program at
East Bigstone
21
21
150
25
20
15
14
100
50
10
6
7
8
2nd
Rig
3rd
Rig
3rd
Rig
-
5
0
2013
2014
2015
2016
2017
2018
East Bigstone development inventory:
• +100 well inventory of extended-reach HZ locations
• Less than 50 percent of total Bigstone land position
17 Drilled
24 Surveyed or Licensed
68 Future Locations
24
DEE
5 YEAR OUTLOOK: FUNDING THE GROWTH
$300
($ millions)
2014 to 2018 Forecast
Cumulative Cash Flow: $796 million
Cumulative Capital: $770 million
$250
Near term source of funding:
cash flow, credit capacity,
JV partnership
$200
21
3rd
Rig
3rd
Rig
Development becomes
self funded with cash
flow in 2015
$150
14
$100
$50
21
2nd
Rig
6
7
1
Rig
1
Rig
8
1
Rig
$0
2013
2014
2015
Capital
2016
Cash Flow
2017
2018
25
DEE
5 YEAR OUTLOOK: PRODUCTION VOLUMES
30,000
(boe/d)
(boe/d per million shares)
Other
Wapiti
Bigstone Montney
25,000
Hythe
Bigstone Cretaceous
Boe/d per million shares
2014 to 2018 Forecast Growth
Boe/d per million shares: 238%
CAGR: 28%
20,000
26
DEE
240
200
160
28,000 boe/d
in 2018
15,000
120
10,000
80
5,000
40
0
2013
2014
2015
2016
2017
2018
5 YEAR OUTLOOK:
300
CASH FLOW GROWTH
($ millions)
($/share)
Funds from Operations
250
2.40
FFOPS
2.00
2014 to 2018 Forecast Growth
Cash netbacks: 116%
CAGR: 17%
Cash flow per share: 619%
CAGR: 48%
200
27
DEE
1.60
$290 million
$1.85 / share
in 2018
150
1.20
100
0.80
50
0.40
0
0.00
2013
Price Assumptions (March 2014)
AECO ($/mcf)
WTI (US $/bbl)
2014
2015
2014
$4.00
$95.50
2016
2015
$3.70
$95.00
2017
2016
$3.70
$95.00
2018
2017
$3.70
$95.00
2018
$3.70
$95.00
HEDGING PROGRAM: PROTECTING CASH FLOW
Natural Gas
Volume (mmcf/d)
% Hedged *
Fixed Price ($/mcf)
Jul - Dec 2014
24.1
57
3.62
2015
24.6
59
3.73
2016
10.9
26
3.68
Jul 2014
100
5
101.10
101.10
Jul – Dec 2014
1,000
53
106.14
-
2015
500
26
95.00
-
Crude Oil
Volume (bbls/d)
% Hedged *
Floor Price (WTI Cdn $/bbl)
Ceiling Price (WTI Cdn $/bbl)
* based on natural gas production of 42.0 mmcf/d and liquids (oil, cond and C5+) production of 1,900 bbls/d
$25.0
$20.0
$15.0
$10.0
$5.0
$0.0
2006
2007
2008
2009
Hedge Gain ($ millions)
2010
2011
2012
AECO ($/mcf)
2013
28
DEE
2017
2.4
6
3.96
29
DEE
2014 MARKET GUIDANCE
2013
2014 Forecast Change
Average Production (boe/d)
8,241
10,000 – 10,500
24%
Exit Production (boe/d)
9,638
11,500 – 12,000
22%
Percentage NGL/light oil
27%
29%
7%
$3.17
$4.50
42%
$98.00
$98.62
1%
Funds from operations (millions)
$39.1
$63 - $68
68%
Net capital (millions)
$82.3
$90 - $95
12%
$138.3
$165 - $170
21%
$160
$190
19%
3.0
2.3
(23%)
Natural gas price (AECO $/mcf)
WTI oil price (US $/bbl)
Net debt (millions)
Credit facilities (millions)
Net debt/Q4 funds from operations (annualized)
DELPHI SUMMARY
• Current inventory of scalable development opportunities:
• Montney land base has grown to 138 sections
• Application of slickwater frac technology is successful
• Gas rates / NGL yields / costs
• Field operations benefiting from continuous operations
• Drives well costs down
• Maximize production rates and reserve recoveries
• Cash generating capability increasing with Montney growth
• Montney field netback of $34/boe for first half of 2014
• Montney C3+ NGL Yields of approx. 100 bbls/mmcf (ave 71% C5+)
• Montney program will accelerate through 2014 and 2015 with:
• Robust economics and shortened payouts
• Significant unbooked value at Bigstone Montney
• Potential to add a second rig in 2015, accelerating the 5 year plan
30
DEE
31
DEE
APPENDIX
BIGSTONE MONTNEY:
32
DEE
PRODUCTION
Total Sales
10,000
10-27-60-23W5
13-30-60-22W5
12-17-59-22W5
16-23-60-23W5
02-01-60-23W5
Revised Type Well
15-24-60-23W5
15-30-60-22W5
02-07-60-22W5
08-21-60-22W5
AVG of all wells minus first 3
15-21-60-23W5
16-15-60-23W5
Variability in initial rates:
• Flow primarily from fractures
• Initial clean-up efficiency
• 30 - 40% frac fluid recovery in first 60 days
Total Sales (boe/d)
1,000
100
Convergence of rates at 4 to 6 months:
• Flow from the rock into fractures
• Very low frac water production rates
All shut in days have been removed
10
0
50
100
150
200
250
300
FLOWING DAYS
350
400
450
500
550
600
BIGSTONE MONTNEY:
33
DEE
PRODUCTION
Field Condensate to Gas Ratio
1,000
FIELD CONDENSATE TO GAS RATIO (bbl/mmcf)
10-27-60-23W5
13-30-60-22W5
12-17-59-22W5
16-23-60-23W5
02-01-60-23W5
03-26-59-23W5
15-24-60-23W5
02-07-60-22W5
Revised Type Well
15-30-60-22W5
08-21-60-22W5
AVG first 3 wells
15-21-60-23W5
16-15-60-23W5
100
10
Stabilized wellhead condensate yield
All shut in days have been removed
1
0
25
50
75 100 125 150 175 200 225 250 275 300 325 350 375 400 425 450 475 500 525 550 575 600
FLOWING DAYS
BIGSTONE MONTNEY: CUMULATIVE PRODUCTION
34
DEE
550
10-27-60-23W5
15-21-60-23W5
13-30-60-22W5
12-17-59-22W5
500
16-23-60-23W5
13-30-60-22W5
02-01-60-23W5
Pre 2014 Wells
03-26-59-23W5
15-24-60-23W5
02-01-60-23W5
"REVISED"
02-07-60-22W5
Type Well
Revised Type Well
15-30-60-22W5
02-07-60-22W5
08-21-60-22W5
First 3 Wells
First 3 Wells
15-21-60-23W5
08-21-60-22W5
16-15-60-23W5
450
Average first year rate = 1,020 boe/d
400
Cumulative BOE's (MBOE)
350
300
Average first year rate = 964 boe/d
250
200
150
100
50
All shut in days have been removed
0
0
50
100
150
200
250
300
FLOWING DAYS
350
400
450
500
550
600
35
DEE
BIGSTONE MONTNEY: WELL DESIGN
“Extended Reach”
HZ Drilling
Evolution of Montney Drilling Depths
6000
Over 4,000 Montney wells drilled in last 5 years
Two - single section HZ
$14 - $15 mm cost
$6.6 mm drilling credits
Depth (m)
5000
Ave. HZ Length
Ave. TVD
4000
3000
2000
2,700
1,315
1,680
890
985
1,880
1,960
1,985
2,045
2,115
2008
2009
2010
2011
2012
445
2,850
1000
0
Drilling Optimization
0
500
1,000
1,500
2,000
2,500
3,000
3,500
4,000
4,500
5,000
5,500
6,000
6,500
16-30
15-10
15-24
13-30
05-02
10-27
15-30
02-01
$6,025
14-23
16-23
15-21
$6,000
$4,614
$5,000
$4,000
35% Faster
TD at approx. 30
days consistently
$3,000
$2,000
$1,000
$0
0
5
10
15
20
25
30
35
Total Rig Days
40
45
DEE
Driving Down Drilling Costs
$7,000
Cost (M$)
Depth (m)
One - 2 section HZ
$9.0 - $10 mm cost
$7.8 mm drilling credits
50
Best cost to date
on 2 mile HZ
36
DEE
BIGSTONE MONTNEY: EVOLUTION OF FRAC DESIGN
150 m
Slickwater Hybrid Frac System
Pumping:
5 times the fluid
2+ times the sand
Evolution of Montney Completions
200
40
500 m
Ave number fracs/well
150
150
30
150
130
100
20
100
70
50
10
30
0
0
2008 2009 2010 2011 2012
DEE
Average fracs per well
Larger slickwater fracs
generate greater stimulated
rock volume
Average tonnes per frac
Ave tonnes/frac
BIGSTONE MONTNEY: COMPLETION OPTIMIZATION
Completions
100,000 bbl water cell
• Have now completed 11 Slickwater Hybrid Fracs
• Significantly greater stimulated rock volume
• Pumped 5X fluid and 2X sand
• Water handling in place
• Lower per frac costs than oil fracs
• Continue optimize frac design/spacing
Gelled Oil Fracs
$6,000
$5,365
$5,000
20 Stages
Completion Cost $k
30 Stages
X $1000 per stage
$4,635
$4,222
$4,129
$4,200
Driving costs down:
• Central water handling
• Switch from propane to natural gas
$4,000
$3,396
10-27
avg $140 k/stage
15-10
avg $156 k/stage
14-23
avg $141 k/stage
4-2
avg $170 k/stage
16-30
avg $206 k/stage
$0
avg $212 k /stage
$1,000
avg $268 k /stage
$3,000
$2,000
Pumps
Slickwater Hybrid Fracs
20 Stages
$4,248
Heater
16-23
15-24
Transfer line from water cell
to wellsite for frac
37
DEE
38
DEE
Percent of Capital Recovered
FURTHER FOCUSING THE DEEP BASIN ASSET BASE
Cash Generating Capability
by Play Type
Bigstone Montney HZ
Bigstone Gething HZ
• Concentrated land base of over 340 sections
• Significant HZ drilling inventory on multiple play types
• Synergistic deep basin play types
Wapiti Vertical MZ
Hythe Falher HZ
Dawson Creek
Time
Hythe
Grande Prairie
Wapiti
Cashflow
• Cash flow from Hythe and Wapiti are being used to
fund the Bigstone Montney program
Cashflow
Bigstone
• Sold $39 million of non-core assets in 2012-13
Tower Creek
THE DEEP BASIN: INFRASTRUCTURE IS CRITICAL
Sexsmith Gas Plant – 210 mmcf/d
Hythe
Knopcik Gas Plant – 71 mmcf/d
Goodfare Gas Plant – 24 mmcf/d
Wapiti Deep Cut Plant – 355 mmcf/d
Wapiti Shallow Cut Plant – 125 mmcf/d
Ownership in 7 compression facilities
and significant gas pipelines in Wapiti area
Wapiti Gas Plant – 457 mmcf/d
Wapiti
Ownership in infrastructure = competitive advantage
• Priority in processing throughput
• Processing cost advantage
• Barrier of entry for competition
Delphi has ownership in 8 gas plants with combined
gross throughput capacity of 1.3 bcf/d
Bigstone Montney Facility
Expansion to 45 mmcf/d in Q1 2014
Bigstone
Bigstone Gas Plant – 85 mmcf/d
Tower Creek
39
DEE
40
DEE
300, 500 – 4th Avenue S.W.
Calgary, Alberta T2P 2V6
Telephone: (403) 265-6171
Facsimile: (403) 265-6207
Email:
info@delphienergy.ca
Website:
www.delphienergy.ca