WCP

SUCCESS
FOCUS
+
+
=
QUALITY ASSETS
MOTIVATED PEOPLE
SUSTAINABLE LIGHT OIL
GROWTH + INCOME PLATFORM
December 2014
Whitecap Profile
• Shares outstanding (MM)
– Basic
– Fully diluted
• Market capitalization ($B)
• Annual dividend ($/share)(1)
• 2015 average production (boe/d)
• 2015 netback ($/boe)
– Operating
– Cash flow
• Reserves (MMboe)(2)
– Proved
– P+P
– RLI (years)(3)
Note:
TSX: WCP
253.3
258.6
$3.0
$0.75 $0.84
40,000
$41.60
$37.15
144.6
205.3
14.8
2015 WTI US$80.00/bbl, C$/US$0.88, Edmonton Par Differential ($7.00) and AECO C$3.50/GJ.
Footnotes are located at the end of the presentation
2
Total Shareholder Return > 10% / Annum
MOTIVATED PEOPLE + QUALITY ASSETS + FOCUS = SUCCESS
•
Founding Principles
– Employees are shareholders
– Light oil focus ($80 to $100 WTI platform)
– Per share growth (cash flow, production, reserves and NAV)
•
Execution Strategy
– Accumulate sustainable assets with growth potential
 large DOIIP with low current recovery factors
 repeatable and expandable capital projects
REPEAT
– Develop and optimize acquired assets
 optimize capital and operating efficiencies, enhance netbacks
 stabilize production and suppress declines
– Expand core operating areas – increase recoverable resource
 complementary “tuck-in” acquisitions for future growth
Total Shareholder Return > 10% / annum
3
WCP Employee Share Ownership
Total Employee Ownership
9,000,000
8,000,000
7,000,000
6,000,000
5,000,000
4,000,000
3,000,000
2,000,000
1,000,000
0
2009
2010
2011
2012
2013
2014
•
Since 2009 insiders increased common share ownership by 120%
•
8.36MM common shares owned by insiders and employees
•
>$125MM of capital at risk currently
4
Results and Track Record
2P Reserves/Share Growth
180
45,000
154
40,000
35,000
122
130
137
160
140
200,000
900
2013 F&D Costs
TP
P+P
Incl. FDC
$20.31
$16.96
P+P Recycle Ratio = 2.3x
793
746
40,000
61
32,050
15,000
10,000
60
40
19,769
14,052
5,000
2010
Actual
2011
Total (boe/d)
Estimate
2012
500
100,000
2013
2014e
2015e
Production / MM shares (fd)
-
205,300
301
251
132,422
50,000
-
200
87,450
5,083
Dec. 31/09
400
300
20
5,657
1,433
-
80
600
496
150,000
(Mboe)
100
87
20,000
(Production / MM shares - fd)
25,000
800
700
643
120
30,000
(boe/d)
250,000
(Mboe / MM shares fd)
Production/Share Growth
13,676
Dec. 31/10
100
38,579
Dec. 31/11
Reserves 2P (Mboe)
Dec. 31/12
Dec. 31/13
Current
-
Mboe / MM FD share
• 21% CAGR per share (2009 – 2014e)
• 29% CAGR per share (2009 – 2013)
• 2014e increase of 5% per share
• 2013 increase of 16% per share
• 2015e increase of 12% per share
• 2014e increase of 9% per share
Footnotes are located at the end of the presentation
5
Results and Track Record
Cash Flow/Share Growth
$600.0
$2.50
$2.03
$500.0
$2.09
$2.00
$1.84
$1.50
($MM)
$1.34
$300.0
$480.0
$542.0
$1.00
$200.0
$0.48
$278.8
$100.0
$0.0
$0.50
$193.9
$11.3
2010
(Cash Flow / share fd)
$1.68
$400.0
$87.2
2011
Actual Estimate
2012
2013
FundsFrom
from Operations ($MM)
Funds
($MM)
2014e
2015e
$0.00
FFO / fd share
• 33% CAGR per share (2010 – 2014e)
• 2014e increase of 10% per share
• 2015e increase of 3% per share
− Avg WTI price decreasing 15% y/y from $94 to $80/bbl WTI
Footnotes are located at the end of the presentation
6
7 Key Attributes to WCP Growth + Dividend Strategy
• Focus on organic per share growth (3 - 5% per year) within cash flow,
supplement with accretive acquisitions
• Conservative total payout ratio and strong balance sheet
• Provide sustainable dividend without DRIP, increase prudently
• Maintain predictable and stable production base
• Strong capital efficiencies in concentrated areas
• Large light oil development drilling inventory
• Management focus on total shareholder return
7
Growth Within Cash Flow – Sustainable Asset Base
$250
Growth
2015 Free Cash Flow by Area
5%
23%
$200
$150
28%
$171
$152
$139
$94
$54
$0
$98
Saskatchewan
SW AB
Annual Forecast
Cash Flow
Capex
Dividends
$21
$96
$85
$77
Operating Income
$117
$54
$100
$50
23%
Pembina
Development Capital
2014e
$480
($311)
($170)
$MM
NW AB/BC
Free Cash Flow
2015e
$542
($360)
($214)
Footnotes are located at the end of the presentation
8
2015 Development Capital
2015 Capex by Area (%)
2015 Well Count (gross)
Saskatchewan
SW AB
21%
27%
1%
Other
24%
27%
NW AB/BC
Pembina
140
130
120
110
100
90
80
70
60
50
40
30
20
10
0
102
24
Sask
SW AB
31
Pembina
23
NW AB/BC
2015e
Development Capital ($MM)
Wells (gross #)
$360
180
9
Predictable and Stable Production Base
• Base and new well production is predictable and repeatable
• High level of certainty of achieving forecasted volumes
• Key characteristics:
– Areally consistent reservoirs
– Large resource in place, limited recovery to date
– Statistically significant number of wells drilled and on production
Whitecap – Change in Base Decline with Time
(for leading 12 months)
35.0%
Decline Rate
30.0%
Base Decline
29.3%
25.0%
23.2%
23%
20.0%
16.5%
15.0%
13.4%
10.0%
2014
2015
13.2%
2016
10
Financial Prudence and Risk Management
C$98.00
C$97.71
15,000
100.00
95.00
10,000
90.00
7,500
85.00
5,000
80.00
2,500
% Hedged
C$/bbl WTI
105.00
12,500
bbls/d
Oil Hedges
C$99.21
17,500
75.00
68%
48%
22%
Q4 2014
2015 *
2016
C$3.82
C$3.77
C$3.59
45,000
Objective:
1) Mitigate price volatility
2) Cash flow predictability for stable
dividend payments and capital
reinvestments
3) Hedge up to 75% for 3 years
4.00
40,000
3.50
25,000
3.25
20,000
15,000
3.00
* 61% 1H/2015 hedged at $98.61/bbl
$/GJ AECO
30,000
GJ/d
Gas Hedges
3.75
35,000
37% 2H/2015 hedged at $97.15/bbl
10,000
2.75
5,000
% Hedged
2.50
67%
29%
13%
Q4 2014
2015
2016
Swaps
Average Floor Price
11
Sensitivities
2015 Cash Flow Sensitivities and Assumptions
Parameter
Oil price (US$WTI)
Gas price (C$/GJ AECO)
Annual Base
Sensitivity
Impact ($000s)
$80.00
+/- $1.00
$5,020
$3.50
+/- $0.10
$1,351
Production (boe/d)
40,000
+/-
100
$1,459
Cash flow netback ($/boe)
$37.15
+/- $0.10
$1,460
3.75
+/- 0.25
$1,037
$0.88
+/- $0.01
$4,795
Interest rate (%)
Exchange rate (CAD/USD)
12
2015 Whitecap Sustainability
Oil (US$WTI)
$65.00
$70.00
$75.00
$80.00
$85.00
Edm Par Diff (US$WTI)
($7.00)
($7.00)
($7.00)
($7.00)
($6.00)
FX (C$/US$)
$0.80
$0.82
$0.85
$0.88
$0.88
AECO (C$)
$3.50
$3.50
$3.50
$3.50
$3.80
$33.75
$35.13
$36.17
$37.15
$38.98
3%
5%
6%
12%
12%
$114
$93
$82
$30
$0
37,100
37,800
38,200
40,000
40,000
$457
$485
$504
$541
$583
Capital
($246)
($267)
($278)
($330)
($360)
Dividend
($214)
($214)
($214)
($214)
($214)
Total payout ratio
101%
99%
98%
100%
99%
1.8
1.7
1.7
1.5
1.4
CF netback ($/boe)
Projected growth per share
Total capital reduction
Average production target
$MM
CF
D/CF
13
Core Areas of Operations
Boundary Drilling inventory
2014/15 wells
Oil
New well netback ($/boe)
115
0 / 10
$54
Drilling inventory
2014/15 wells
New well netback ($/boe)
60
4/2
$45
Montney
Oil
Dunvegan Drilling inventory
2014/15 wells
Oil
New well netback ($/boe)
165
9 / 11
$43-$47
Development Inventory 2,229
• 100% Light Oil
• 10+ Years inventory
BRITISH COLUMBIA
Boundary
Lake
ALBERTA
Valhalla
North
Elmworth
Karr Deep
Peace
River
Arch
SASKATCHEWAN
Basin
Cardium
Oil
Drilling inventory
662
2014/15 wells
41 / 55
New well netback ($/boe) $58-$63
Nisku
Oil
Drilling inventory
2014/15 wells
New well netback ($/boe)
4
1/0
$42
Viking
Oil
Drilling inventory
1,199
2014/15 wells
108 / 102
New well netback ($/boe)
$54
West
Pembina/ Central AB
Garrington
Elnora
Whiteside/
Lucky Hills
Footnotes are located at the end of the presentation
West
Central
SK
14
Elnora Nisku Oil Acquisition
• Recently consolidated to 100% WI
• Operated, 35o API light sweet oil, focused asset
–
–
–
–
Largest Nisku oil discovery in the past 20 years
Nisku zone at 1,900m depth, 18 – 30m thick
$42/boe netback (97% oil + NGLs), $6/boe op cost
Conventional reservoir – 15 producing vertical wells
• Low cost, low decline with controllable growth
–
–
–
–
Natural water drive supplemented with waterflood
Nearby analog pools with RF greater than 50%
July/15 waterflood approval, potential to accelerate
Increase to 5,800 boe/d with 14% decline after
$80
$70
$60
$50
$40
$30
Cumulative 5 Year ($MM)
$0
$317
($27)
ALBERTA
FCF
$290
West Central
– Recovered to date = 4.8% (1.44 MMbbls)
– Possible oil RF = 65% (3rd party simulation)
$62 $50
$12
2015
$6
2016
Operating Income
Cash Flow
Capital
• Gross DOIIP 30 MMbbls (25.5 MMbbls net)
$79 $73
$68
$65
$58 $55
$20
$10
• Exceptional free cash flow
Elnora Free Cash Flow
$90
$3
2017
Development Capital
$3
2018
$50
$47
$3
2019
Free Cash Flow
Edmonton
Calgary
15
Cardium Horizontal Resource Play
• Cardium oil resource play – repeatable and expandable
– Light sweet oil (39° API)
Edmonton
West Pembina
East Pembina
– Strong operating and cash flow netbacks ($58 - $63/boe)
– Low risk optimization of 7 legacy Cardium oil waterfloods
• Industry leading capital efficiencies (2011 to current)
– Focus on improving capital efficiencies through
ERH drilling and advancing frac technologies
• Drilling program
– 2014: 41 wells (9 ERH)
Willesden Green
ALBERTA
Edmonton
– 2015: 55 wells (20 ERH)
Garrington
Calgary
• Cardium Gross DOIIP 1,690 MMbbls (1,245 MMbbls net)
Red Deer
Ferrier
West Central
– Recovered to date 4.4% (73.7 MMbbls)
Hz Development
Areas
– Possible oil RF = 14%
Hz Wells
Core Focus Areas
Cardium
Sand Trends
Calgary
Footnotes are located at the end of the presentation
16
West Pembina Cardium Legacy Characteristics
• Unitized waterfloods, 38o API light oil, 1,700m depth
− 6 Units (46 – 100% WI)
− 83% oil + NGLs
− Average base decline of 5%
Industry Hz Wells
Acquired Hz Wells
WCP Drilling
Non-Unit Lands
Unit Lands
• Non-unitized lands offsetting waterfloods
CPOU#1
69.5%
− 94% avg WI
− 91% oil + NGLs
• Upside evaluation to date
CCU#2
100%
CCU#4
66.4%
− 153 (94.6 net) locations identified


CPDU#1
79.1%
107 (59 net) Unit
46 (35 net) Non-Unit
• Gross DOIIP 640 MMbbls (68% Unit, 32% Non-Unit)
– Recovered to date 7.3% (46.5 MMbbls)
– Possible oil RF = 20 - 25%
Cardium - Type Curves
350
300
Boe/d
250
200
150
100
CCU#1
87.2%
50
0
0
3
6
East Pembina
9
12
Months
15
West Pembina
18
21
24
PCU#11
45.8%
Garrington
Footnotes are located at the end of the presentation
17
Exceptional Type Curve Economics
East Pembina
Cardium
Garrington
Cardium (Standard)
Garrington
Cardium (ERH)
West Pembina
Cardium
$2.50
$3.00
$3.60
$3.00
Production, IP30 (boe/d)
230
320
476
317
Production, IP365 (boe/d)
83
113
164
159
P+PA Reserves (Mboe)
182
227
321
222
Year 1 Oil + NGLs (%)
89%
85%
84%
92%
NPV BT10 ($MM)
$2.23
$2.98
$4.66
$4.28
Profit to investment ratio
0.9
1.0
1.3
1.4
Rate of return (%)
49%
59%
102%
189%
Payout (years)
1.88
1.61
1.02
0.65
Reserve cost ($/boe)
$13.74
$13.22
$11.21
$13.51
Production efficiency ($/boe/d – IP365)
$30,120
$26,549
$21,951
$18,868
Initial operating netback ($/boe/d)
$62.94
$57.65
$58.02
$62.69
4.6
4.4
5.2
4.6
Type Well Economics
DCE&T ($MM)
Recycle ratio
Footnotes are located at the end of the presentation
18
Western Saskatchewan Viking Oil
• Light oil (36° API) Viking resource play
Strong capital efficiencies, short payout periods
Decline mitigation via waterflood
–
–
Type Well Economics
• Improving capital efficiencies
SASKATCHEWAN
Drill & complete costs continue to improve
 decreased 29% from 2011 to current
Type curve improvements since 2011
–
–
West Central
Saskatchewan
• Drilling program
2014: 108 Hz wells
2015: 102 wells
–
–
Lucky Hills/
Whiteside
• Gross DOIIP 1,314 MMbbls (1,133 MMbbls net)
Recovered to date 2.1% (27.4 MMbbls)
Possible oil RF = 9.1%
–
–
Whitecap Viking Type Curve Evolution
150
Production, Boe/d
2013 Type Curve
118
2012 Type Curve
100
2011 Type Curve
85
75
68
58
50
25
0
0
1
2
3
4
5
6
7
8
9
Producing Month
10
11
12
13
14
$0.93
DCE&T ($MM)
Production, IP30 (boe/d)
118
Production, IP365 (boe/d)
56
P+PA Reserves (Mboe)
80
Year 1 Oil + NGLs (%)
79%
NPV BT10 ($MM)
$1.55
Profit to investment ratio
2014 Type Curve
125
Lucky Hills/
Whiteside Viking
15
1.7
Rate of return (%)
193%
Payout (years)
0.74
Reserve cost ($/boe)
$11.63
Production efficiency ($/boe/d – IP365)
$16,607
Initial operating netback ($/boe/d)
$53.62
4.6
Recycle ratio
Footnotes are located at the end of the presentation
19
Deep Basin – Dunvegan Oil
• Dunvegan light oil (39° - 42° API)
– Recently expanded opportunity base
Dunvegan – Type Curves
500
• Play characteristics
416 boe/d
IP30
400
Boe/d
– Large OOIP of 6 to 15.5 MMboe/section
– Exceptional reservoir quality: 2 – 3x thicker,
more perm than Cardium
– No formation water
– Low declines and strong stabilized rates
300
200
299 boe/d
IP30
100
• Established significant opportunity base
0
– 91 (87.2 net) total drilling locations
– Current production of 2,500 boe/d
0
3
6
9
12
15
18
21
24
Months
Karr/Simonette
Elmworth
ALBERTA
• Drilling program
– 2014: 9 Hz wells (exceeding type curves)
– 2015: 11 Hz wells (3 ERH)
Grande Prairie
Deep
Basin
Edmonton
Calgary
20
Exceptional Type Curve Economics
Elmworth
Dunvegan
Karr/Simonette
Dunvegan
$3.25
$4.30
Production, IP30 (boe/d)
293
543
Production, IP365 (boe/d)
174
264
P+PA Reserves (Mboe)
431
514
Year 1 Oil + NGLs (%)
76%
77%
NPV BT10 ($MM)
$4.78
$5.75
Profit to investment ratio
1.5
1.3
Rate of return (%)
78%
125%
Payout (years)
1.33
0.86
Reserve cost ($/boe)
$7.54
$8.37
Production efficiency ($/boe/d – IP365)
$18,678
$16,288
Initial operating netback ($/boe/d)
$42.50
$47.16
5.6
5.6
Type Well Economics
DCE&T ($MM)
Recycle ratio
Footnotes are located at the end of the presentation
21
Boundary Lake Asset Characteristics
• Operated, 35o API light oil, focused land base
–
–
–
–
Boundary Lake WI Production
Avg 54% WI in 3 operated units
Boundary Lake zone at 1,300m depth
$54/boe netback (91% oil + NGLs)
Current: 254 (138 net) producers, 88 (47 net) injectors
5% decline
• Legacy oil pool under a pattern waterflood
30 yrs of history
– No development capital since 1998
– Consistent decline of 5% over the past 30 years
1974
2014
• Upside evaluation to date
– 115 (63.4 net) locations identified (74 Hz wells)
• Drilling program
– 2014: 0 wells
– 2015: 10 wells (5 Hz, 5 vertical)
Unit #2
Triassic E
BRITISH
COLUMBIA
Boundary
Lake
• Gross DOIIP 600 MMbbls (335 MMbbls net)
– Recovered to date = 37.5% (225 MMbbls)
– Possible oil RF = 45%
Unit #1
22
Exceptional Type Curve Economics
Boundary
Vertical
Boundary
Horizontal
$1.20
$1.80
Production, IP30 (boe/d)
32
80
Production, IP365 (boe/d)
30
74
P+PA Reserves (Mboe)
107
214
Year 1 Oil + NGLs (%)
94%
94%
NPV BT10 ($MM)
$2.34
$5.60
Profit to investment ratio
2.0
3.1
Rate of return (%)
60%
109%
Payout (years)
2.00
1.31
Reserve cost ($/boe)
$11.21
$8.41
Production efficiency ($/boe/d – IP365)
$40,000
$24,324
Initial operating netback ($/boe/d)
$55.84
$51.37
5.0
6.1
Type Well Economics
DCE&T ($MM)
Recycle ratio
Footnotes are located at the end of the presentation
23
Economic Sensitivities to WTI US$/bbl
Profit to Investment Ratio
3.5
3.3
3.0
2.8
2.5
2.3
2.0
1.8
1.5
1.3
1.0
0.8
0.5
0.3
0.0
-0.3
-0.5
Rate of Return
400%
350%
300%
250%
200%
150%
100%
50%
$60
$70
$80
$90
$100
$110
$120
Payout (yrs)
0%
$60
4.0
$10,000
3.5
$8,000
3.0
$70
$80
$90
$100
$110
$120
$110
$120
NPV / Well (M$)
$6,000
2.5
$4,000
2.0
1.5
$2,000
1.0
$0
0.5
0.0
$60
$70
$80
$90
$100
$110
$120
-$2,000
$60
$70
$80
$90
$100
Note: Based on -$7.00 WTI/Edm Lt Diff, C$3.50/GJ, CAD/USD 0.88
24
2015 Outlook
2013
2014e
2015e
Average production (boe/d)
19,769
32,050
40,000
Development capital ($MM)
$190
$311
$360
Wells drilled (gross)
100
163
180
$38.64
$41.00
$37.15
$279
$480
$542
Operational
Financial
Cash flow netback ($/boe)
Cash flow ($MM)
•
per share
Total dividend ($MM)
•
annual per share
Year-end net debt ($MM)
•
Note:
debt/cash flow
$1.84
$2.03
$2.09
$93
$170
$214
$0.62
$0.75
$0.84
$401
$830
$862
1.4x
1.5x
1.6x
Q4 2014 WTI US$78.00/bbl, C$/US$0.88, Edmonton Par Differential (US$6.40) and AECO C$4.05/GJ.
2015 WTI US$80.00/bbl, C$/US$0.88, Edmonton Par Differential (US$7.00) and AECO C$3.50/GJ.
Footnotes are located at the end of the presentation
25
The Whitecap Investment Opportunity
Growth
• Visible growth per share; CF, production, reserves, NAV
• 10+ years high netback light oil development drilling locations
Income
• Meaningful and consistent monthly dividends without DRIP
• Potential for prudent dividend-growth longer term
Total Return
• Management focus on annual Total Shareholder Return
• Disciplined approach to capital and risk management (debt & hedging)
26
Research Coverage
Current Price Targets
•
•
•
•
•
•
•
•
AltaCorp Capital Inc.
Barclays
BMO
CIBC World Markets Inc.
Cormark Securities
Desjardins Capital Markets
Dundee Securities Ltd.
FirstEnergy Capital
$17.50
$19.00
$19.00
$20.00
$22.00
$18.00
$18.00
$18.75
•
•
•
•
•
•
•
GMP Securities
Macquarie Equity Research
National Bank Financial
Peters & Co.
RBC Capital Markets
Scotiabank Global
TD Securities
$19.25
$24.00
$21.00
$19.00
$20.00
$21.00
$22.00
3 Year Price – WCP:CA
27
TSX:WCP
www.wcap.ca
December 2, 2014
28
Whitecap IMO Acquisition (May 1, 2014)
• Purchase Price - $692.7MM
Boundary Lake
• Production
− Current 6,500 boe/d (83% oil + NGLs)
− Capability 7,550 boe/d (83% oil + NGLs)
 16% base decline
 96% operated
 60.5% average working interest
$92,000 / boe/d
• Reserves (McDaniel March 1, 2014)
− TP 36.2 MMboe (82% oil + NGLs)
− TP+P 49.0 MMboe (81% oil + NGLs)
 PDP is 65% of TP
 TP is 74% of TP+P
 21 year RLI
Valhalla
Deep Basin
$19.15 / boe
$14.15 / boe
3.7x RR
West Pembina
Pembina
• Large Resource-in-Place – 1.3 Billion bbls (0.8 Net)
($MM)
2P NPV10
926
ARO
(67)
Unbooked upside (identified to date) 379
Total PV
$1,238
Willesden Green
Ferrier
Acquired Lands
WCP Lands
Garrington
Footnotes are located at the end of the presentation
29
Whitecap Elnora Acquisition (Oct 1, 2014)
• Purchase Price – $240MM
−
−
Production:
Reserves:
• Transaction Metrics
−
−
2015 Production:
Reserves:
2,000 boe/d (97% oil + NGLs), 0% decline for 2 years - 14% after
TP 9.4 MMboe (94% oil + NGLs)
P+P 13.6 MMboe (94% oil + NGLs), 15 year RLI
$72,081 / boe/d
TP $28.47 / boe
P+P $19.57 / boe
2015 cash flow multiple
Recycle ratio
4.1x
2.4x
• Acquisition Rationale
−
−
−
−
−
−
Ability to grow light oil production 150% spending 17% of cash flow
Adds significant free cash flow: $42MM in 2015 and $68MM in 2016
Reduce corporate decline rate by 1%: 23% base decline in 2015
Increases light oil weighting: 2% to 76% in 2015
Adds additional low decline high netback waterflood asset
Allows further dividend increase while maintaining long-term sustainability
• Accretive on key measures (leverage neutral)
Cash flow per share
Production per share
2P reserves per share
NAV per share
Effective
Oct. 1, 2014:
2014
1%
1%
1%
2%
2015
5%
5%
30
Growth + Free Cash Flow – Viking Type Economics
• Increases Whitecap sustainability
+ Outstanding capital efficiency of $17,000/boe/d ($930K DCE&T, 56 boe/d IP(365))
+ Excellent netbacks - $58.00/boe (79% oil & liquids)
= Payout of initial capital in 8 - 9 months and 21% free cash flow in year 1
Cash Flow – Whiteside Viking Type Well
$1,600,000
160
PAYOUT
140
Economics
P/I 2.0
ROR > 200%
$1,200,000
($)
$1,000,000
120
100
$800,000
80
$600,000
60
$400,000
40
$200,000
20
$0
Free cash flow
already in Year 1
Year 1
FCF
Year 2
Capital
Other Costs
Year 3
Op. Costs
Royalties
(boe/d)
$1,400,000
0
Boe/d
31
Footnotes
2014 price assumptions throughout this presentation are actual commodity prices for January to September. Q4 2014 WTI US$78.00/bbl, C$/US$0.88, Edmonton Par
Differential (US$6.40) and AECO C$4.05/GJ. 2015 WTI US$80.00/bbl, C$/US$0.88, Edmonton Par Differential (US$7.00) and AECO C$3.50/GJ.
Slide 2:
(1) Dividend increased to $0.84 per annum effective January 2015.
(2) Whitecap’s reserves based on McDaniel & Associates Ltd.’s (McDaniel) reserve report effective December 31, 2013 plus
acquisition reserves announced on November 20, 2013, March 17, 2014, and on August 20, 2014.
(3) Based on production of 38,000.
Slide 5:
(1) F&D calculations are done in accordance with NI 51-101. Refer to Whitecap’s 2013 Annual Information Form for F&D performance for the past
three years and additional disclosures.
Slides 15-17, 19, 22:
(1)
(2)
(3)
(4)
Slide 19:
(1) Lucky Hills Viking assumes 70% Crown, 30% Freehold economics and for comparison purposes Viking IP’s included flared gas volumes.
Whiteside Viking assumes 80% Crown, 20% Freehold economics.
Slide 25:
(1) 2014e D/CF ratio based on annualized Q4 cash flow.
Slide 28:
(1) Refer to the Oil and Gas Advisory section of this presentation for additional information on DOIIP.
Refer to the Oil and Gas Advisory section of this presentation for additional information on DOIIP.
Reserves are based on McDaniel’s reserve report effective March 1, 2014.
Booked P+P oil RF calculated as (proven + probable reserves + current production) / DOIIP (all as of March 1, 2014 effective date).
Possible oil RF calculated as (proven + probable + possible reserves + current production) / DOIIP (all as of March 1, 2014 effective date).
32
Forward-Looking Statements
Special Note Regarding Forward-Looking Statements and Forward-Looking Information
This presentation contains forward-looking statements and forward-looking information within the meaning of applicable securities laws. The use of any of the words
"expect", "anticipate", "continue", "estimate", "objective", "ongoing", "may", "will", "project", "should", "believe", "plans", "intends" and similar expressions are intended
to identify forward-looking information or statements. More particularly and without limitation, this presentation includes forward-looking information and statements about
our strategy, plans and focus, future dividends and dividend policy, forecast annual growth rates, the source of funding of dividend payments, planned capital expenditures
and the source of funding of our capital program, projected payout ratios and dividend yields, expected future production and product mix, anticipated tax horizon, the
quantity and estimated value of reserves, waterflood expansion plans and the results to be obtained therefrom, forecast operating and financial results including funds
from operations, free cash flow, and operating and cash flow netbacks, future decline rates, drilling inventories and drilling plans, hedging plans and the benefits to be
obtained from our hedging program, anticipated debt levels and our debt to cash flow ratio, forecasted commodity prices and differentials, forecasted exchange rates,
anticipated production costs and capital efficiencies and the benefits to be obtained from recent acquisitions.
This presentation contains certain information relating to economics for drilling opportunities in the areas that Whitecap has an interest. Such information includes, but is
not limited to, anticipated production rates, anticipated reserves, anticipated capital costs, anticipated finding and development costs, anticipated ultimate reserves
recoverable and recycle ratios. Certain of the drilling opportunities identified have no associated reserves or resources which can presently be classified as recoverable. As
such the information presented with respect to such drilling opportunities do not represent estimates of future production or estimates of reserves or future net revenue
associated with the drilling opportunities. No resources may ultimately be recovered from the drilling opportunities identified herein which have no associated reserves. In
addition, references in this presentation to initial production (“IP”) rates and production type curves and other short-term production rates are useful in confirming the
presence of hydrocarbons, however such rates are not necessarily indicative of long-term performance or ultimate recovery. While encouraging, readers are cautioned not
to place reliance on such rates in calculating the aggregate production for Whitecap.
Additionally, readers are advised that historical results, growth and acquisitions described in this presentation may not be reflective of future results, growth and
acquisitions with respect to Whitecap.
The forward-looking statements and information are based on certain key expectations and assumptions made by Whitecap and its management, including expectations
and assumptions concerning general economic conditions in Canada, the United States and elsewhere, and oil and gas industry conditions, including applicable royalty
rates and environmental and tax laws and regulations. Although Whitecap believes that the expectations and assumptions on which such forward-looking statements and
information are based are reasonable as of the date hereof, undue reliance should not be placed on the forward-looking statements and information because Whitecap can
give no assurance that they will prove to be correct.
Since forward-looking statements and information address future events and conditions, by their very nature they involve inherent risks and uncertainties. Actual results
could differ materially from those currently anticipated due to a number of factors and risks including, but not limited to the risks associated with the oil and gas industry in
general.
Readers are cautioned that the foregoing list of factors is not exhaustive. The forward-looking statements and information contained in this presentation are made as of the
date hereof and Whitecap 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.
33
Oil and Gas Advisory
"Boe" means barrel of oil equivalent on the basis of 6 mcf of natural gas to 1 bbl of oil. Boe's may be misleading, particularly if used in isolation. A boe conversion ratio of 6
mcf: 1 bbl is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead. In
addition, given that the value ratio based on the current price of crude oil as compared to natural gas is significantly different from the energy equivalency of 6: 1, utilizing a
conversion on a 6:1 basis may be misleading as an indication of value.
The estimated values of the future net reserves of the reserves disclosed in this presentation do not represent the market value of such reserves. The estimates of reserves
and future net reserve for individual properties may not reflect the same confidence level as estimates of reserves and future net reserve for all properties due to the effects
of aggregation.
This presentation contains references to estimates of oil classified as Discovered Oil Initially In Place (“DOIIP”) which are not, and should not be confused with, oil reserves.
DOIIP is defined in the Canadian Oil and Gas Evaluation Handbook as the quantity of oil that is estimated to be in place within a known accumulation prior to production.
DOIIP is divided into recoverable and unrecoverable portions, with the estimated future recoverable portion classified as reserves and contingent resources and the
remainder as at evaluation date is by definition classified as unrecoverable. The accuracy of resource estimates is, in part, a function of the quality and quantity of available
data and of engineering and geological interpretation and judgment. The size of the resource estimate could be positively impacted, potentially in a material amount, if
additional delineation wells determine that the aerial extent, reservoir quality and/or the thickness of the reservoir is larger than what is currently estimated based on the
interpretation of seismic and well control. The size of the resource estimate could be negatively impacted, potentially in a material amount, if additional delineation wells
determine that the aerial extent, reservoir quality and/or the thickness of the reservoir are less than what is currently estimated based on the interpretation of the seismic
and well control.
Contingent resources are those quantities of oil estimated, as of a given date, to be potentially recoverable from known accumulations using established technology or
technology under development, but which are not currently considered to be commercially recoverable due to one or more contingencies. Contingencies may include
factors such as economic, legal, environmental, political and regulatory matters, or a lack of markets. It is also appropriate to classify as contingent resources the estimated
discovered recoverable quantities associated with a project in the early evaluation stage. All contingent resources represented in this document are considered Economic
Contingent Resources based on the McDaniel & Associates Consultants Ltd. January 1 Price Forecast and an economic hurdle rate of the before tax net present value at a
discount rate of 10% being greater than 0 (i.e. ROR >= 10%). The primary contingency which prevents the classification of Whitecap's contingent resources as reserves is
capital budgeting restraints that allow the resources to be developed within a reasonable time frame. This time frame can be defined as 3 – 4 years. As additional drilling
and/or development takes place, it is expected that some or all of the contingent resources will be booked as reserves.
The best estimate of the contingent resources is determined on the basis that it is equally likely that the actual remaining quantities recovered will be greater or less than
the best estimate. If probabilistic methods are used, there should be at least a 50 percent probability (P50) that the quantities actually recovered will be equal or exceed the
best estimate. The remainder of the DOIIP beyond what has been cumulatively produced, classified as proved plus probable plus possible reserves, or classified as
contingent resource is currently considered to be the unrecoverable portion.
Estimates of DOIIP and contingent resources described herein are estimates only; the actual resources may be higher or lower than those calculated in the independent
evaluation. There is no certainty that it will be economically viable to produce any portion of the resources. The estimates of COOIP and Economic Contingent Resources
have been prepared internally by a qualified reserves evaluator in accordance with NI 51-101 and the COGEH handbook and are effective as of January 1, 2013. The
estimates of Reserves presented herein have been prepared by McDaniel & Associates Consultants Ltd., Whitecap’s independent qualified reserves evaluator.
34
Non-GAAP Financial Measures
NON-GAAP MEASURES
This presentation includes non-GAAP measures as further described herein. These non-GAAP measures do not have a standardized meaning prescribed by
International Financial Reporting Standards (“IFRS or, alternatively, “GAAP”) and therefore may not be comparable with the calculation of similar measures by
other companies.
“Basic payout ratio” is calculated as cash dividends declared divided by funds from operations.
“Cash dividends per share” represents cash dividends declared per share by Whitecap.
“Cash netbacks” are determined by deducting cash general and administrative and interest expense from Operating netbacks.
“Funds from operations” represents cash flow from operating activities adjusted for changes in non-cash working capital, transaction costs and asset retirement
settlements. Management considers funds from operations and funds from operations per share to be key measures as they demonstrate Whitecap’s ability to
generate the cash necessary to pay dividends, repay debt, fund asset retirement obligations and make capital investments. Management believes that by excluding
the temporary impact of changes in non-cash operating working capital, funds from operations provides a useful measure of Whitecap’s ability to generate cash
that is not subject to short-term movements in non-cash operating working capital. Refer to the “Funds from Operations, Payout Ratio and Dividends” section of
this report for the reconciliation of cash flow from operating activities to funds from operations.
“Net debt” is calculated as bank debt plus working capital deficiency adjusted for risk management contracts. Net debt is used by management to analyze the
financial position and leverage of Whitecap.
“Operating netbacks” are determined by deducting royalties, production expenses and transportation and selling expenses from oil and gas revenue. Operating
netbacks are per boe measures used in operational and capital allocation decisions.
“Total Payout Ratio” is calculated as development capital plus cash dividends declared divided by funds from operations.
35

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