Attached files
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| 8-K - FORM 8-K - Chaparral Energy, Inc. | d446788d8k.htm |
 Chaparral Energy
Wells Fargo Conference
December, 2012
Exhibit 99.1 |
 This
presentation contains "forward-looking statements" within the meaning of Section 27A of the
Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of
1934, as amended. These forward-looking statements are subject to
certain risks, trends and uncertainties that could cause actual results to
differ materially from those projected. Among those risks, trends and
uncertainties are our ability to find oil and natural gas reserves that are
economically recoverable, the volatility of oil and natural gas prices and
significantly depressed natural gas prices since the middle of 2008, the
uncertain economic conditions in the United States and globally, the decline in the values
of our properties that have resulted in and may in the future result in additional
ceiling test write- downs, our ability to replace reserves and sustain
production, our estimate of the sufficiency of our existing capital sources,
our ability to raise additional capital to fund cash requirements for future
operations, the uncertainties involved in prospect development and property
acquisitions or dispositions and in projecting future rates of production or
future reserves, the timing of development expenditures
and
drilling
of
wells,
hurricanes
and
other
natural
disasters,
including
the
impact
of
the
oil spill in the Gulf of Mexico on our present and future operations, the impact of
government regulation, and the operating hazards attendant to the oil and
natural gas business. In particular, careful
consideration
should
be
given
to
cautionary
statements
made
in
the
various
reports we
have
filed with the Securities and Exchange Commission. We undertake no duty to update or
revise these forward-looking statements.
2
2 |
 3
3
Company Representative
Company Representative
Joe Evans
Chief Financial Officer
& Executive Vice President
Mark Fischer
Chief Executive Officer
& President
John Zimmerman
Director of Corporate Finance
& Investor Relations |
 Chaparral Overview
Chaparral Overview
Founded in 1988, Based in Oklahoma City
Core areas —
Mid-Continent (Oklahoma) and Permian Basin (W. Texas)
Oil-weighted producer (64% oil; 36% gas); R/P ratio 18 years
Second largest oil producer in Oklahoma
Stable 1P base with large potential upside –
740 MMBoe
Near-term growth potential through drilling in
conventional &
emerging plays ~ 450,000 acres Long-term growth through CO
2
EOR –
74 fields
1
As of 12/31/11 using SEC methodology
Company Statistics
Production (Boe/d)
Proved Reserves (MMBoe)
Proved Reserves PV-10 ($mm)
TTM EBITDA ($mm)
4
4
1
1
~26,100
Q3, 2012
156.3
$2,309
$313 |
 Operating Areas
Operating Areas
As of December 31, 2011 (SEC)
Core Area
Growth Area
Acreage
Field Offices
Headquarters
North Texas
Reserves: 3.9 MMBoe, 3% of total
Production: 0.5 Mboe/d, 2% of total
Permian Basin
Reserves: 19.3 MMBoe, 12% of total
Production: 3.6 MBoe/d, 15% of total
Company Total
December
2011
proved
reserves
–
156.3
MMBoe
2011
average
daily
production
–
23.7
MBoe/d
Acreage
(gross
/
net):
1,178,489
/
590,324
Val Verde
Basin
Sabine
Uplift
Midland
Basin
Delaware
Basin
Ouachita
Uplift
Arkoma
Basin
Fort
Worth
Basin
Anadarko
Woodford
Basin
OKC
Gulf Coast
Reserves: 3.2 MMBoe, 2% of total
Production: 0.9 MBoe/d, 4% of total
Mid-Continent
(Anadarko Basin & Central Oklahoma)
Reserves: 122.2 MMBoe, 78% of total
Production: 17.0 MBoe/d, 72% of total
Ark-La-Tex
Reserves: 7.2 MMBoe, 5% of total
Production: 1.3 MBoe/d, 6% of total
5
5 |
 Strong
Record of Reserve and Production Growth Strong Record of Reserve and Production
Growth Year-End SEC Reserves (MMBoe)
(1)
2003 –
2011 CAGR = 15%
Annual Production (MMBoe)
2003 –
2011 CAGR = 16%
Chaparral’s reserve replacement ratio averaged 422% per year since 2003
6
6
Year
Oil
Gas
2007
$96.01
$6.80
2008
$44.60
$5.62
2009
$61.18
$3.87
2010
$79.43
$4.38
2011
$96.19
$4.11
1)
Reserves as of December 31
for each year calculated
using flat SEC
pricing per the following:
6
6
0
20
40
60
80
100
120
140
160
180
2003
2004
2005
2006
2007
2008
2009
2010
2011
51
73
103
151
164
113
142
149
156
0
1
2
3
4
5
6
7
8
9
2.6
3.2
4.2
5.4
6.8
7.1
7.6
8.1
8.7
8.8-9.0
2003
2004
2005
2006
2007
2008
2009
2010
2011
2012B |
 Current Production -
2012
Current Production -
2012
2012 Production by Quarter
7
7
7
7
In the 3 Quarter Chaparral increased production by 13.4% over the
previous quarter rd
-
5,000
10,000
15,000
20,000
25,000
30,000
Q1
Q2
Q3
23,278
23,018
26,098 |
 Net
Debt / EBITDA Liquidity ($mm)
Financial Position to Execute Strategy
Strong Financial Position
No senior note maturities before 2020
Hedge positions in place to secure cash
flow in near term
Budget CAPEX within free cash flow
(including divestiture proceeds)
$325
$300
$400
8
8
*
* Pro-Forma for $150mm Senior Notes Add-On and Increased Borrowing Base;
subject to 4.5x Debt / EBITDA Borrowing Base covenant
* Pro-Forma for $150mm Senior Notes Add-On
5.6x
4.4x
4.9x
3.2x
3.3x
3.8x
2.3x
2.0x
2.0x
0.0x
0.0x
0.1x
2007
2008
2009
2010
2011
Q3, 2012
Total net debt to EBITDA
Net secured debt to EBITDA
$88
$55
$77
$429
$407
$290
$514
2007
2008
2009
2010
2011
Q3, 2012
2012
Pro
Forma*
$15
$300
$400
$550
2012
2016
2017
2018
2019
2020
2021
2022
Current Maturity Profile ($mm) |
 Capital Budget ($mm)
Capital Budget ($mm)
Component
2008
2009
2010
2011
2012
Budget
2012
Expanded
Budget
2012
%
Drilling
$168
$76
$196
$172
$131
$201
44%
EOR
24
14
36
86
127
168
37%
Enhancements
53
32
39
32
26
16
3%
Acquisitions
46
18
41
17
15
40
9%
Other (P&E,
Capitalized G&A, etc)
48
14
32
28
31
35
7%
Total
$339
$154
$344
$336
$330
$460
100%
Key Drilling Areas
Northern OK Mississippi
Horizontal
$73
Anadarko Cleveland Sand
46
Anadarko Granite Wash
22
Marmaton
15
Bone Spring / Avalon
10
Hogshooter
7
Other
28
Total
$201
9
9
EOR Field
N. Burbank
$104
Panhandle Area
60
Other
3
Total
$168
*99% of Capital Program is Oil Focused |
 10
10
Drilling Resource Potential
Drilling Resource Potential |
 Substantial Resource Potential for Near-Term
Growth
Substantial Resource Potential for Near-Term
Growth
11
11
Near-Term
2,522 Unrisked (1,184 Risked) Net Undrilled Wells
156 MMBoe Proved Reserves Plus 583 MMBoe Unproved Resource Potential
Conventional
Drilling
(ROR
50%
-
75%)
Anadarko Granite Wash
Anadarko Cleveland Sand
Unconventional
Resource
Play
Drilling
(ROR
35%
-
75%)
Northern Oklahoma Mississippi Play (NOMP)
~ 260,000 acres
Panhandle Marmaton
~ 48,000
acres
Anadarko Woodford Shale
~ 23,000 acres
Bone Spring/Avalon Shale
~ 19,000 acres
11
11 |
 Northern Oklahoma Mississippi Play
The Northern Oklahoma Mississippi Play (“NOMP”) is a
key near–term focus area for Chaparral
Chaparral acreage over 260,000 net acres in the NOMP
Over 132 MMBoe of potential
1,600 unrisked drilling well inventory
Chaparral Acreage
12
12
Overview
NOMP Asset Map
NOMP Well Economics
IP Rates:
100 - 700 Boe/d
EUR:
100 - 400 MBoe
Well Cost:
$2.5 - 4.0 million
% Oil:
60% - 90%
IRR:
35% - 75%
KS
OK
Emerging
Core |
 13
13
NOMP: Recent Results
NOMP: Recent Results
Current
Net
Production
–
3,200
Boepd
(65%
Oil)
2012 Capital -
$73 mm
NOMP Core (93,000 Net Acres)
Significant industry activity in the play
Drilled or participated in 37 wells to date (18 operated); 2 WOCU
1-3 additional wells in 2012
Average IP ~600 Boepd
Current
Net
Production
–
2,700
Boepd
51% Oil
Emerging NOMP (167,000 Net Acres)
In de-risking phase –
industry activity increasing
Drilled 6 wells to date
Average IP ~200+ Boepd
Current
Net
Production
–
500
Boepd
95% Oil |
 14
14
NOMP Core Type Curve
NOMP Core Type Curve |
 15
15
NOMP Emerging Type Curve
NOMP Emerging Type Curve |
 Marmaton Shelf Play
Marmaton Shelf Play
Johnston 1H-24
IP +300 Boepd
Leatherman 1H-14
2012 Location
Lamaster 1H-23
IP +500 Boepd
(90% Oil)
Jay 1H-1098
IP +140 Boepd
Wright 1H-1099
2012 Location
Marmaton Production
Chaparral Acreage
Net Acreage
48,000
EUR/well (MBoe)
Cost per Well (MM$)
$3.6
Cornell 1H-30
2012 Location
Buy Area
Ochiltree Co, TX
16
16
150 |
 17
17
Chaparral:
Chaparral:
A Growing Mid-Continent
CO
2
EOR Company
A Growing Mid-Continent
CO
2
EOR Company |
 # of
Active Producer
CO2-EOR Projects
31
22
8
7
7
7
6
5
4
4
4
Total
105
Source: April 2012 Oil & Gas Journal
Note: Chaparral projects include the North Burbank Unit
18
18
Chaparral
Chaparral
is
is
a
a
Leader
Leader
in
in
the
the
CO2-EOR
CO2-EOR
Industry
Industry
Chaparral is the third most active CO2-EOR producer in the U.S.
|
 CO
2
EOR Focused Areas
CO
2
EOR Focused Areas
19
19
CO
2
Project Inventory
74 units with 1P, 2P & 3P EOR reserve
8 units with proved reserves
8 units with CO
2
injection
CO
2
Infrastructure –
473 Miles
318 miles of active line
68 miles under construction
87 miles of inactive line
CO
2
Supply
47 MMscf/D of existing CO
2
supply
43 MMscf/D new CO
2
supply
CO2 Tertiary Recovery Projects
Panhandle Area
Burbank
Area
Permian Basin
Central
Oklahoma
Area |
 20
20
Currently Owned CO
2
Development Potential and
Infrastructure
Currently Owned CO
2
Development Potential and
Infrastructure
Total OOIP
3,735 MMBo
Primary Production
628 MMBo
Secondary Recovery
597 MMBo
Tertiary Potential
410 MMBo
Net Tertiary Potential
197 MMBo
Existing
CELLC
CO
Pipelines
Existing Third Party CO Pipelines
Planned
CELLC
CO
Pipelines
Proposed
CELLC
CO
Pipelines
Owned
Active
CO
fields
Owned Potential CO
fields
CO
Source
Locations
Coffeyville Fertilizer Plant
Koch Fertilizer Plant
Agrium Fertilizer Plant
Arkalon Ethanol Plant
2
2
2
2
2
2
2 |
 EOR
2012 Capital Budget (1)
EOR 2012 Capital Budget
(1)
21
21
Budget by Category
($mm)
2011
Actual
2012
Budget
2012
Expanded
Budget
Infrastructure / Pipelines
14
90
106
Drilling
17
13
24
Enhancements / CO
2
Purchases
55
24
37
Total
$86
$127
$168
2012 Field Projects ($mm)
Panhandle
Area
Permian
Basin
Central
Oklahoma
Area
Burbank
Area
(1)
Does not include Capitalized G&A
Panhandle Area
Camrick
Area
$18
Farnsworth
Unit
28
NE
Hardesty
(Non-op)
7
Booker
Area
4
Other
3
$60
Burbank
Area
North
Burbank
Unit
$104
Central
Oklahoma
NW
Velma
Hoxbar
$3
Permian
No planned expenditures for 2012 |
 Processing Rate: The Key to Improved Rate of
Return
Processing Rate: The Key to Improved Rate of
Return
22
22
Time
25% hcpv Inj./Yr
10% hcpv Inj./Yr
HMU Model: Processing Rate v. Reserve Recovery
•
CO
2
Injection initiated Sep’07
•
Processing Rates Average 25% hcpv Inj./Yr
Hovey Morrow Unit (HMU) |
 Monthly Incremental EOR from Active CO
2
Projects
23
23 |
 Chaparral –
Potential EOR Production Growth
Chaparral –
Potential EOR Production Growth
0
5,000
10,000
15,000
20,000
25,000
30,000
35,000
40,000
2010
2015
2020
2025
2030
2035
2040
Net Oil Production
24
24
Additional production from
non Business Plan projects
meeting corporate economic
hurdles
Additional CO2 Plan w/ +100
mmcfpd in 2015 at Burbank
Business Plan w/ 95 mmcfpd
in 2015 at Burbank
Business Plan
Add C02
Others |
 25
25
North Burbank CO
2
Development
North Burbank CO
2
Development |
 North
Burbank Unit – Overview
North Burbank Unit –
Overview
Chaparral’s
North
Burbank
Unit
is
its
largest
EOR
field
and
plans
to
introduce
CO
2
injection
into
the
North
Burbank Unit in 1Q 2013
Chaparral
anticipates
that
it
will
spend
$800
million
associated
with
this
EOR
project
throughout
the
life
of
the field
26
26
26
26
Total OOIP
1,163 MMBbls
Primary Production
239 MMBbls
Secondary Recovery
211 MMBbls
Tertiary Potential
119 MMBbls
Net Tertiary Potential
100 MMBbls
Burbank Area:
Net Potential: 100 MMBoe, 51% of total
|
 Burbank in Perspective
Burbank in Perspective
27
27
Secondary
Development
Primary
Development
Tertiary
Development
110 Years
“CO2 EOR”
“Waterflood”
+8,000 BOPD |
 28
28
North Burbank Unit –
Miscibility Pressure Build
November 2012
Average
pressure
1622 psia
Ph-I Vicinity
Phase I
Halo Area
Phase II |
 Coffeyville CO
2
System
Coffeyville CO
2
System
29
29
The Coffeyville CO
2
System
$84 million of total capital expenditures
23,500 HP compression facility
68.3-mile 8-inch pipeline with potential
capacity of approximately 60 MMcf/d.
CO
2
is sourced from the CVR Partners
fertilizer plant in Coffeyville, KS.
Online and operational in early 2013
Oklahoma
Kansas
Coffeyville CO2 System
Asset Map
CO2
System
Panhandle
Coffeyville
CO2
System |
 Coffeyville CO
2
Compression Facility
Coffeyville CO
2
Compression Facility
30
30 |
 Coffeyville CO
2
Facility: Foundation Construction
Coffeyville CO
2
Facility: Foundation Construction
31
31 |
 Coffeyville CO
2
Pipeline: Construction
Coffeyville CO
2
Pipeline: Construction
32
32 |
 33
33
Coffeyville CO
2
Pipeline: Construction
Coffeyville CO
2
Pipeline: Construction |
 34
34
Other CO
2
Injection Projects
Other CO
2
Injection Projects |
 Secondary
Development
Primary
Development
Tertiary
Development
Camrick CO
2
–EOR Flood
Camrick CO
2
–EOR Flood
35
35
+1,500 BOPD |
 36
36
North Perryton CO
2
–EOR Flood
North Perryton CO
2
–EOR Flood
Secondary
Development
Primary
Development
Tertiary
Development
+600 BOPD |
 37
37
Primary
Development
Secondary
Development
Tertiary
Development
Booker Area CO
2
–EOR Flood
Booker Area CO
2
–EOR Flood
+700 BOPD
1
10
100
1,000
10,000
1
10
1,000
10,000
Jan-80
Jan-90
Jan-00
Jan-10
Jan-20
100 |
 38
38
Primary
Development
Tertiary
Development
Secondary
Development
Farnsworth Area CO
2
–EOR Flood (West Side Only)
Farnsworth Area CO
2
–EOR Flood (West Side Only)
+2,900 BOPD
10
100
1,000
10,000
100,000
10
100
1,000
10,000
100,000
Jan-50
Jan-60
Jan-70
Jan-80
Jan-90
Jan-00
Jan-10
Jan-20 |
 39
39
Potential of 740 MMBoe
Potential of 740 MMBoe
Near-term + Long-term
strategy yields significant
value increase
~ 70% Oil
* Woodford, Bone Spring, Avalon, Cleveland Sand, Granite
Wash, and Marmaton
740
132
200
145
107
156
0
100
200
300
400
500
600
700
800
2011 Proved
Reserves
+NOMP
Drilling
Potential
+EOR
Potential
+ Developing
Emerging
Plays*
+Other
Drilling
=Total
Potential
Near-term focus on NOMP
De-risk play, unlock value
Production growth
Long-term focus on EOR
Low-risk production upside
Long-life, stable production |
 Financial Overview
Financial Overview
40
40 |
 41
41
Financial Summary
Financial Summary
2009
2010
2011
3Q 2012
Price
Oil & NGL –
Wellhead ($/Bbl)
$55.04
$74.53
$87.52
$76.13
Gas –
Wellhead ($/Mcf)
$3.51
$4.36
$4.08
$2.82
Production (MMBoe)
7.6
8.1
8.7
2.4
Oil & NGL (MMBbls)
3.9
4.0
5.0
1.5
Gas (Bcf)
22.6
23.7
21.6
5.2
Financial Data ($mm)
Operating Expenses:
Lease Operating Expenses
$94.1
$106.1
$121.4
$35.3
Production and Ad Valorem Taxes
20.3
26.5
34.3
8.8
General and Administrative Expenses (excludes noncash deferred
comp) 22.7
27.3
38.3
12.2
Interest Expense
$90.1
$83.6
$96.7
$24.1
EBITDA
$224
$288
$313
$86
Total Capital Expenditures
$154
$344
$336
$140 |
 Financial Metrics per Boe
Financial Metrics per Boe
Production (Boe) / Day
LOE / Boe
EBITDA / Boe
G&A / Boe
42
42
19,323
20,926
22,055
23,713
26,098
0
10,000
20,000
30,000
2008
2009
2010
2011
3Q, 2012
$17.04
$12.32
$13.18
$14.03
$14.69
$0
$5
$10
$15
$20
2008
2009
2010
2011
3Q, 2012
$3.16
$3.11
$3.72
$4.86
$5.36
2008
2009
2010
2011
3Q, 2012
$39.43
$29.47
$35.56
$35.98
$35.88
$0
$10
$20
$30
$40
$50
2008
2009
2010
2011
3Q, 2012
$0
$1
$2
$3
$4
$5
$6 |
 Operating Statistics
2011 Results
2012
Guidance
Capital Expenditures
$336 million
$460 million
Production
8.7 MMBoe
8.8 -
9.0 MMBoe
General and Administrative
$4.86/Boe
$5.75 -
$6.25/Boe
Lease Operating Expense
$14.03/Boe
$14.25 -
$14.75/Boe
2011 Results and 2012 Guidance
2011 Results and 2012 Guidance
43
43 |
 44
44
% of Total Proved Reserves Hedged (as of November 23, 2012)
Hedge Portfolio
Note:
Dollars
represent
average
strike
price
of
hedges
(includes
all
derivative
instruments)
Gas Basis Hedges
YR
Price
% TP
’12
$
0.23
78%
’13
$
0.20
75%
’14
$
0.23
66%
$4.44
$4.31
$3.95
$94.45
$98.48
#DIV/0!
$ 108.79
$96.28
$73.85
$ 114.26
$99.94
$77.88
$ 105.43
$93.49
$76.67
0%
10%
20%
30%
40%
50%
60%
70%
80%
90%
100%
Nov -
Dec 2012
2013
2014
3 -
Way Oil Collars
Oil Swaps
Gas Swaps |
 Question & Answer
Question & Answer
45
45 |