CLR Investor and Analyst Day 2014 Presentation

Forward-Looking Information
Cautionary Statement for the Purpose of the “Safe Harbor” Provisions of the Private Securities Litigation Reform Act of 1995
This presentation includes “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act
of 1934. All statements included in this presentation other than statements of historical fact, including, but not limited to, statements or information concerning the
Company’s future operations, performance, financial condition, production and reserves, schedules, plans, timing of development, returns, budgets, costs, business
strategy, objectives, and cash flow, are forward-looking statements. When used in this presentation, the words “could,” “may,” “believe,” “anticipate,” “intend,”
“estimate,” “expect,” “project,” “budget,” “plan,” “continue,” “potential,” “guidance,” “strategy,” and similar expressions are intended to identify forward-looking
statements, although not all forward-looking statements contain such identifying words. Forward-looking statements are based on the Company’s current expectations
and assumptions about future events and currently available information as to the outcome and timing of future events. Although the Company believes the
expectations reflected in the forward-looking statements are reasonable and based on reasonable assumptions, no assurance can be given that such expectations will
be correct or achieved or that the assumptions are accurate. When considering forward-looking statements, readers should keep in mind the risk factors and other
cautionary statements described under Part I, Item 1A. Risk Factors included in the Company’s Annual Report on Form 10-K for the year ended December 31, 2013,
registration statements and other reports filed from time to time with the Securities and Exchange Commission (“SEC”), and other announcements the Company
makes from time to time.
The Company cautions readers these forward-looking statements are subject to all of the risks and uncertainties, most of which are difficult to predict and many of
which are beyond the Company’s control, incident to the exploration for, and development, production, and sale of, crude oil and natural gas. These risks include, but
are not limited to, commodity price volatility, inflation, lack of availability of drilling, completion and production equipment and services and transportation
infrastructure, environmental risks, drilling and other operating risks, lack of availability and security of computer-based systems, regulatory changes, the uncertainty
inherent in estimating crude oil and natural gas reserves and in projecting future rates of production, cash flows and access to capital, the timing of development
expenditures, and the other risks described under Part I, Item 1A. Risk Factors in the Company’s Annual Report on Form 10-K for the year ended December 31, 2013,
registration statements and other reports filed from time to time with the SEC, and other announcements the Company makes from time to time.
Readers are cautioned not to place undue reliance on forward-looking statements, which speak only as of the date hereof. Should one or more of the risks or
uncertainties described in this presentation occur, or should underlying assumptions prove incorrect, the Company’s actual results and plans could differ materially
from those expressed in any forward-looking statements. All forward-looking statements are expressly qualified in their entirety by this cautionary statement. This
cautionary statement should also be considered in connection with any subsequent written or oral forward-looking statements that the Company, or persons acting on
its behalf, may make.
Except as otherwise required by applicable law, the Company disclaims any duty to update any forward-looking statements to reflect events or circumstances after the
date of this presentation.
2
CLR: Exceptional Future
Quantifying the Potential
Jack Stark
President and COO
Exceptional Future From Growing Assets
Potential Undrilled Net Wells
10,000
20,000
Net Unrisked Resource Potential +
Proved Reserves
9,600
18,600
18,000
9,000
Other
8,000
Net Unrisked Resource Potential MMBoe
Potential Undrilled Net Wells
16,000
7,000
14,000
12,000
Other
11,400
SCOOP
6,000
10,000
4,900
5,000
8,000
SCOOP
8.5 Billion
Boe
Potential
4,000
Bakken
6,000
Bakken
3,000
4,000
2,000
2,000
1,000
0
Investor Day 2012
Investor Day 2014
160 MB & TF1/320 TF2 Spacing 160 MB & TF1/320 TF2 Spacing
160 Woodford Spacing
120-320 Woodford Spacing
Proved Reserves
Proved
Reserves
0
Investor Day 2012
Investor Day 2014
1.1 Billion
Boe
Proved
160 MB & TF1/320 TF2 Spacing 160 MB & TF1/320 TF2 Spacing
160 Woodford Spacing
120-320 Woodford Spacing
Bakken
SCOOP
Other
4
Superior Portfolio: CLR Bakken and SCOOP Type Curves
SCOOP
Condensate
1,725 MBoe
(13% Oil)
73% ROR
Boe per day
1,000
SCOOP
Springer
940 MBoe
(67% Oil)
105% ROR
Bakken
603 MBoe
(85% Oil)
45% ROR
100
SCOOP Condensate
SCOOP Oil
655 MBoe
(57% Oil)
30% ROR
SCOOP Springer
SCOOP Oil
Bakken 603
ROR based on: $90 oil /$4 gas
10
0
10
20
30
Month
40
50
60
5
Northern
Region
The Bakken
Maximizing Profitability
Gary Gould
Senior Vice President,
Operations and Resource Development
State of the Bakken Field
– Steady industry rig count
– New infrastructure in place
– Operators shifting from HBP to full-field
development
•
Recovery factor has increased with
density drilling
Higher recovery factor = more
recoverable resources
– 62-96 billion barrels of oil
(on a stock tank basis)
•
Enhanced completions are unlocking
more potential
– ~25% uplift in production
– Potential EUR uplift
300
1,200
ND & MT Rigs
Oil (MBo per day)
Gas (MBoe per day)
250
1,000
200
800
150
Development
Efficiency
600
100
400
50
200
0
Jan-09
(MBoe Per Day)
– Recovery factor of ~15%
– Evidence from Hawkinson simulation
suggests as high as 20%+
•
Bakken Field Production and Rig Count
Orderly development underway
Rig Count
•
0
Jan-10
Jan-11
Jan-12
Jan-13
Jan-14
8
Bakken: CLR Track Record of Successful Execution
Track record of successful execution
•
•
•
58% annual production growth rate over
the last three years
•
110,000
90,000
80,000
Industry leader in natural gas capture
60,000
Industry leader in density pilots and lower
bench testing
D&C capital reduced to $7.5 million/well
prior to enhanced completion testing
(late 2013)
BOEPD
NetNet
Boe
per day
100,000
Largest quarterly production gain in the
most recent quarter (+11,100 Boe per day)
– CLR selling 85%+ of gas volumes
– Industry average of 60-70%
•
Bakken Net Production Growth
70,000
50,000
40,000
30,000
20,000
10,000
0
1Q 09
1Q 10
1Q 11
1Q 12
1Q 13
Q1 14
9
Bakken: What’s New for Continental?
• Detailed geologic and reservoir studies completed
75 geologic areas,
microseismic study and reservoir simulation
• Resource potential refined and quantified
4.1 Billion Boe potential, ~11,800 net undrilled
wells and TF2 included
• Inventory ranked and prioritized
28 type curve economic models, development
drilling prioritized by highest ROR
• Density pilots providing clarity for full-field development
~7-9 wells in each MB and TF1, ~3-5 wells in TF2;
based on current model
• Enhanced completions very promising
~25% uplift in production;
Potential uplift in EUR
• High-volume lift installations
Increasing production for
enhanced ROR
10
Bakken: CLR Culture of Maximizing Profitability
If You Like Our Track Record, You’ll Like Our Future Even More
Optimization: Maximizing Profitability
•
Resource potential refined and inventory ranked
–
–
•
Drilling activity: Prioritized based on ROR
–
–
•
Larger proppant volumes
Slickwater or hybrid fluids
Production lift optimization: Increasing production
–
–
–
•
Development drilling activity
Realized capital savings from pad drilling
Completions: Bigger with ~25% production uplift
–
–
•
Quantity Inventory: 4.1 Billion Boe undrilled potential
Quality Inventory: Type curve economic models by area
Long stroke pumping units
Electric submersible pumps
Gas lift
Well density for maximum profitability
–
–
Maximizing economics
Evaluating optimum combinations of well spacing, completion design and artificial lift
11
The Bakken
Bakken Petroleum System Update, Middle Bakken and Three Forks
Detailed Reservoir Studies
Updated Resources Potential
Leasehold Update
Tony Moss
Senior Exploration Geologist
Jennifer White
Senior Petrophysicist
Stan Wilson
Vice President,
Resource Development
Don Key
Northern Land Manager
Middle Bakken and TF1 Delivering Excellent Results
Grade A reservoirs of the Bakken
Petroleum System
•
IMMATURE BAKKEN
Maximizing economics in proven areas
Expanding economic footprint
OOIP and type curve EUR models
supports up to 8 wells per zone
10,000
7,500
# HZ Producers
Proximity to source rock
6% average porosity
Focused on optimizing completion
and lift technology
–
–
•
ND
–
–
CANADA
MT
•
TF
Bakken
Bakken Wells, n= 6,808
TF Wells, n= 2,495
5,000
2,500
18 Miles
TF1 Producer
0
Middle Bakken Producer
13
Gamma Ray
Resistivity
Lower Three Forks Update
Lodgepole
Productivity proven, economic areas identified
Upper
BAKKEN
Middle
73 wells completed in LTF to date, 59% CLR-operated
Integrating into field development to maximize ROR and
recovery of OOIP
Industry LTF Producers
Lower
1
THREE FORKS
BAKKEN PETROLEUM SYSTEM
308’
MBKKN
•
•
Investor Day
2012
Investor Day
2014
2
TF2
2
53
3
TF3
0
18
4
TF4
0
2
Total
2
73
Birdbear
14
Lower Three Forks Well Performance
LTF Prospective Outline
300
Cumulative Production (MBoe)
Inside Prospective Outline
Outside Prospective Outline
IMMATURE BAKKEN
Prospective outline defined and confirmed by
CLR and industry LTF results
ND
MT
CANADA
250
200
150
100
50
603 MBoe Model
0
0
100
200
300
400
500
600
700
800
900
1000
Days on Production
15
Defining the Lower Three Forks Fairways
Geologic Requirements for LTF Development:
Bakken Structure Map
CANADA
CANADA
–
MT
MT
ND
ND
1. Lower Bakken source rock
Highest oil saturation in areas where
the Lower Bakken Shale > 10’ thick
STRUCTURAL ENHANCEMENT
2. Pore pressure gradient
–
MAXIMUM
OVERPRESSURE
(>0.65 psi/ft)
3. Structural position
–
–
Vertical permeability enhancement
Areas of structural deformation
IMMATURE BAKKEN
–
Pore pressure > capillary pressure to
source Lower Benches from LBS
> 0.65 psi/ft
4. Reservoir quality
18 Miles
+
18 Miles
16
Bakken Petroleum System (BPS)
Current Productive Fairways
•
CANADA
MT
Multiple zones contribute to recoverable
reserves throughout the Bakken Field
ND
•
MB & TF1
Extent of saturation in lower reservoirs of
the system is heavily influenced by
bottom-hole pressure
MB, TF1, TF2
Basin Province
MB, TF1, TF2 & TF3
Maximum overpressure +
structure
MB, TF1 & TF2
Maximum overpressure
MB & TF1
Transitional area
MB or TF1
More normally pressured
areas
Stratigraphic targets and development
pattern specific to geologic areas
MB, TF1,
TF2 & TF3
MB or TF1
IMMATURE BAKKEN
•
Contributing Zones
MB & TF1
18 Miles
17
BPS: Detailed Petrophysical Analysis
Basin-Wide Petrophysical Model
Connected Porosity
Isolated Porosity
IMMATURE BAKKEN
Three Forks 2nd Bench
Regional Mapping of Petrophysical Data by Geologic Area
FIB-SEM Cube
Three Forks 2nd Bench
White-Light Core Photo
+
+
Routine Core Analysis
Log Analysis
Advanced Core Analysis
18
Bakken Field-Wide Analysis
•
Field-wide petrophysical model provides
more clarity of BPS than ever before
•
Wells with core utilized to build
petrophysical model
12 CLR-operated cores
•
•
•
•
•
–
IMMATURE BAKKEN
–
CANADA
MT
~3,400 Bakken/Three Forks wells
completed since Investor Day 2012
ND
•
Porosity/saturation
Capillary pressure
Geochemical analysis
FIB-SEM 3D analysis
High-tier petrophysical data
20 industry cores/logs
•
Porosity/saturation
•
226 well logs analyzed
•
Mapped petrophysical attributes of all
horizons in BPS
Legend:
CLR Core
Industry Core
Well log
18 Miles
19
Updated Bakken OOIP and Estimated Recovery
•
413 - 643 BBo in place (P50 – P10)
CLR UPDATED ESTIMATES
Expected recovery factor increased to
~15% based on production from
density pilots and reservoir simulation
–
•
•
Projection of recoverable reserves increased
across the field
Guiding effort to increase profitability
by identifying areas with highest
recoverable reserves and well
economics
More granular perspective on CLR
inventory
–
–
OOIP gridded by horizon, by DSU
Inventory calculated by DSU based on OOIP
and PDP production
Original Oil In Place
413-643 BBo
Est. Recovery Factor
~15%
Potentially Recoverable
Reserves
62-96 BBo
OOIP and Recoverable Reserves (Billion Bo)
•
1,000
643
413
96
100
62
P50
P10
10
1
OOIP
Recoverable
Reserves
20
Bakken Net Unrisked Resource Potential and Drilling Inventory
8+ years of 600+ MBoe wells
Potential Undrilled Net Wells
Net Unrisked Resource Potential
4,500
14,000
4,100
Net Unrisked Resource Potential (MMBoe)
Potential Undrilled Net Wells
10,000
4,000
11,800
12,000
9,200
8,000
6,000
4,000
2,000
3,500
3,400
TF2
3,000
TF1
2,500
2,000
MB
1,500
Proved
Undeveloped
Reserves
1,000
500
0
Investor Day 2012
160 MB & TF1/320 TF2 Spacing
Investor
InvestorDay
Day2014
2012
160 MB & TF1/320 TF2 Spacing
0
Investor Day 2012
Investor Day 2014
160 MB & TF1/320 TF2 Spacing 160 MB & TF1/320 TF2 Spacing
21
CLR: Bakken’s #1 Leasehold Owner
Bakken total
•
1,197,884 net acres
North Dakota
•
892,824 net acres
91% HBP in de-risked area
120 Miles
‒
Montana
•
305,060 net acres
•
84% HBP in de-risked area
Expansion Mode
25
Miles
Continental Acreage
De-risked area
22
Continued Growth through Trades, Acquisitions and Leasing
Progress since 2012 CLR Investor Day
• Strategic trades to consolidate
Leasehold Acquired By:
operated position
11%
‒ 47 trades with 22 industry
participants
32%
• Acquisitions
‒ 24 acquisitions
‒ 81,200 net acres
57%
• Leasing
‒ 144,600 net acres
Acquisitions
Leasing
Strategic Trades*
* Strategic trades included to show scope of activity
23
The Bakken
Conclusions on Density Pilots
Hawkinson Microseismic and Reservoir Simulation Study
Stan Wilson
Vice President,
Resource Development
Allan Schlosser
Senior Staff Geophysicist
Density Pilots Increasing Recovery and Bringing Value Forward
from Bakken Petroleum System
6 producing density pilots
4 CLR:
•
•
–
CLR Rollefstad 1,320’
CLR Wahpeton 660’
CLR: Mack, Lawrence, Hartman 660’s
COP: 6 density pilots
KOG: 1 density pilot
OAS: 2 density pilots
WLL: 5 density pilots
Testing 4 – 8 wells per zone
15 of the 23 pilots include wells in LTF
IMMATURE BAKKEN
•
800’: Polar and Smokey
17 future pilots in progress/announced
–
–
–
–
–
•
1,320’: Hawkinson, Rollefstad, Tangsrud
660’: Wahpeton
2 KOG:
•
•
CLR Tangsrud 1,320’
ND
–
CANADA
MT
•
CLR Hawkinson 1,320’
18 Miles
Producing Density Pilot
Future Density Pilot
25
Hawkinson Takeaways
•
Technical and economic success
Industry’s largest microseismic project
Full DSU development validated
(4 zones on 1,320’ spacing)
– Average well performance exceeds 603
MBoe model by 50%+
– Project ROR >100%
–
–
•
Reservoir simulation conclusions
–
–
–
–
–
Stimulations were contained within BPS
Stagger wellbores instead of stacking
No lateral communication on 1,320’
spacing in Middle Bakken and Three Forks
Opportunity for enhanced stimulations
Modeling supports future infill MB drilling
26
Hawkinson Unit Performance
Hawkinson: Middle Bakken
250,000
200,000
200,000
Cumulative Boe
Cumulative Boe
Hawkinson: Three Forks
250,000
150,000
100,000
50,000
150,000
100,000
50,000
0
0
100
200
0
300
0
100
Days
MB
TF1
200
300
Days
TF2
TF3
603 MBoe Model
Area Average
27
Hawkinson Cutting-Edge Microseismic Project
• Largest downhole project ever
conducted industry-wide
– 283 stages monitored and imaged
– ~1.2 million data points recorded
• Provides unprecedented 3D
visualization of a fully drilled and
stimulated Drilling Spacing Unit
(DSU)
10 wells monitored
28
Microseismic Study Results
Model of sand-propped fractures for all zones
• Significant un-propped area exists between
wellbores (1,320’ spacing / 330’ stage)
– Models suggest sand-propped fractures extend
280’-340’ in each direction from the
wellbores based on integrating the
microseismic data with stimulation modeling
• Stimulations are contained vertically within
2 miles
the Bakken Petroleum System
– Clearly documents the stimulations break
through Lower Bakken and Three Forks shales
• Stimulations migrated towards existing
producers (lower pressure)
– Highlights the potential for significant unstimulated rock at unit boundaries
– Supportive evidence for reducing toe & heel
setbacks
1 mile
10 wells monitored
29
3D Visualization: Hawkinson Microseismic Study
Model of sand-propped fractures
10 wells monitored
30
Reservoir Simulation Results
Opportunity to test Middle Bakken infill
•
Staggered wellbores can improve
drainage in the BPS
•
Enhanced completions improve
productivity and potentially reduce
wells needed per DSU
•
Stimulation energy is drawn towards
existing wells
–
–
Guidelines for developing units with
producing wells
Section lines are inadequately drained
Colors are Pressure Values
•
Hawkinson: Middle Bakken Formation only
Sand-Propped Model
Reservoir Model – May
2014
31
Hawkinson Pressure Depletion Simulation
Reservoir Pressure
May 2014
Cumulative production
prior to simulation forecast
totaled 2.5 Million Boe
32
Rollefstad
• Conclusions
– Staggering wellbores provide
superior density pattern to stacking
– Strong Three Forks 2 production
– Optimizing artificial lift
90,000
80,000
Cumulative Boe
70,000
60,000
50,000
40,000
30,000
20,000
10,000
0
0
20
MB
40
TF1
TF2
Days
60
TF3
80
100
603 MBoe Model
* Rollefstad Federal 8-2H-3 well not included due to mechanical/operational issues
33
Wahpeton: 660’ Test Results
• Conclusions
– Exceptional early results for Middle Bakken wells at 660’ spacing
– Overall results indicate drilling pattern in Lower Bench was beyond
optimal density
• Noteworthy, one TF2 well was drilled as close as 330’ spacing
100,000
90,000
Cumulative Boe
80,000
70,000
60,000
50,000
40,000
30,000
20,000
10,000
0
0
20
MB
TF1
40
TF2
Days
TF3
60
80
100
603 MBoe Model
34
The Bakken
Operational Optimization
Boost Economics/Maximize Value
Drilling, Completions & Production
Alan McNally
Drilling Manager
Chris Nichols
Completions Manager
Tyler Bolton
Senior Reservoir Engineer
Kevin Murray
Production Engineering
Manager
Bakken Drilling Performance
Cycle Times
Improvement
(2012 – 2014)
Spud to TD
20%
Lateral Days
28%
Mobilization
Year
2012
2014
15%
Wells Drilled on
Multi Well Pads
Wells per Rig per Year
20
15
16
12
12
8
4
45%
75%
0
2012
2013
2014 Est.
2014: 82% of fleet is currently pad capable
36
Bakken Drilling Performance
• Operational gains
̶ Technology
̶
• Bits
• Motors
• Fluids
Tool reliability
̶
• 31% one run laterals (2-mi)
• 10% improvement in MWD
Continual upgrading of fleet
• 16% reduction in nonproductive time (NPT)
• 2% of NPT is rig repair
Avg. Drilling Cost per Lateral Foot
$410
$398
$390
$372
$370
$354
$350
$337
$330
$324
$320
$310
$310
$290
$270
$250
2012
4Q
12
2Q 13
13Q4
4Q 13
2Q 14
37
Bakken Enhanced Completions
Comprehensive Testing Program
• CLR has most completion tests of
any Bakken operator
-
Range of tests to-date included:
•
•
•
-
Larger proppant volume
Slickwater
Hybrid
Greatest aerial extent of tests—
all areas of operations
Williams, Mountrail, McKenzie and
Dunn Counties showing greatest
potential for uplift
Legend:
Area of improved well performance
Slickwater
Large proppant volume
Hybrid
38
2014 Bakken Enhanced Completions
Large Proppant Volume
Advantages
Slickwater Advantages
Hybrid Advantages
• High conductivity
• Fastest transition from old designs
• Least amount of horsepower
• Complex fractures
• Upward growth is limited
• Complex fractures
• High near wellbore conductivity
• Moderate horsepower
requirements
39
Bakken Enhanced Completion Evolution
Proppant Pumped per Well
2013
• Various types of proppant in
different areas
6,000,000
5,000,000
Variables: hybrid, slickwater and
larger proppant volume
–
•
•
Expanded testing to broader geologic
area
Increasing job volumes
Implemented program-wide testing
in high impact areas– rate of return
driven
Transformed ND stimulation fleet
while maintaining cost structure
2.7MMlbs
4.6MMlbs
3.2MMlbs
2,000,000
1,000,000
0
2014
• 60-well test program
–
4.2MMlbs
4,000,000
3,000,000
•
5.4MMlbs
Q3 2013
$0.70
Q4 2013
Q1 2014
Q2 2014
Q3 2014 E
Pumping and Materials Cost per lb Proppant
$0.66
$0.65
$0.64
$0.60
$0.60
$0.58
$0.56
$0.55
$0.50
$0.45
$0.40
Q3 2013
Q4 2013
Q1 2014
Q2 2014
Q3 2014 E
40
Bakken Enhanced Completions
Cross Link Large Proppant Volume
Cross Link Large Proppant Volume
Average Offset Well (610 MBOE)
603 Model
200
The incremental $0.9 MM of capital to
conduct the enhanced completion is returned
in less than a year
90,000
80,000
180
160
70,000
140
60,000
120
50,000
100
15,000 Boe (20%) Production
increase after 180 Days
40,000
30,000
80
60
20,000
40
10,000
20
0
0
0
20
40
60
80
100
120
140
160
180
Well Count
Cumulative Production (Boe)
100,000
200
Days
Capital and Economics
Type
Standard
CWC
Incr.
Capital
CWC
200K+ Proppant
$7.8MM
$0.9MM
$8.7MM
Incr. EUR (MBoe)
104
+17%
Time to Incr.
Payout
Incr.
NPV10
Incr. Rate
of Return
0.9 yrs
$1.9MM
100%
41
Bakken Enhanced Completions
Slickwater
Slick Water
Average Offset Well (574 MBOE)
603 Model
200
The incremental $1.3 MM of capital to
conduct the enhanced completion is returned
in less than a year
120,000
180
160
100,000
140
120
80,000
27,000 Boe (27%)
Production increase after
300 Days
60,000
40,000
100
80
60
40
20,000
20
0
0
0
50
100
150
200
250
300
Well Count
Cumulative Production (Boe)
140,000
350
Days
Capital and Economics
Type
Standard
CWC
Incr.
Capital
CWC
Slickwater
$7.8MM
$1.3MM
$9.1MM
Incr. EUR (MBoe)
156
+27%
Time to Incr.
Payout
Incr. NPV10
Incr. Rate
of Return
0.9 yrs
$2.7MM
100%
42
Bakken Enhanced Completions
Hybrid Type
Hybrid 180K+ Proppant
Average Offset Well (501 MBOE)
The incremental $1.4 MM of capital to
conduct the enhanced completion is returned
in less than a year
120,000
603 Model
200
180
22,000 Boe (57%) Production
increase after 100 Days
160
100,000
140
120
80,000
100
60,000
80
60
40,000
40
20,000
20
0
0
0
20
40
60
80
Days
100
120
140
Well Count
Cumulative Production (Boe)
140,000
160
Capital and Economics
Type
Standard
CWC
Incr.
Capital
CWC
200K Hybrid
$7.8MM
$1.4MM
$9.2MM
Incr. EUR (MBoe)
167
+33%
Time to Incr.
Payout
Incr. NPV10
Incr. Rate
of Return
0.9 yrs
$2.9MM
100%
43
2014 Bakken Enhanced Completions To Date
Williams, McKenzie, Mountrail and Dunn Counties
Completion
Method
Gross Incremental Completed
Wells
Capital
Well Cost
Tested
($MM)
($MM)
Range of
Production
Uplift (%)
Average 30-90
Day Uplift
Capital
Increase (%)
Incremental EUR
MBoe
%
Incremental
ROR (%)
Large Proppant
Volume
22
$0.9
$8.7
10-180%
5-15%
12%
104
17%
>100%
Slickwater
16
$1.3
$9.1
0-100%
20-35%
17%
156
27%
>100%
Hybrid
6
$1.4
$9.2
0-120%
45-60%
18%
167
33%
>100%
Total
44
Conclusions:
Path Forward:
• Completion testing successful in key
parts of basin
• Optimize completions by testing greater
stage counts (40+) and larger volumes
• Hybrid/slickwater showing greatest
uplift and economics
• Transition to hybrid/slickwater exclusively
in good areas
• Some areas showed variable results
• Focus efforts on best economic areas;
continue to test new technologies in others
44
Optimized Artificial Lift & Production Facilities
Increasing Production
• Artificial lift optimization
– Long stroke pumping unit (LSU)
– Electric submersible pump (ESP)
– Gas lift (GL)
• Optimized water handling
– Production and disposal facilities
– Gathering and distribution systems
• Central tank batteries
45
Higher Capacity Artificial Lift Installations
Increasing by Quarter
ESP
Gas Lift
Long Stroke Unit
40
# of Lift Installations
35
34
Quarterly % of
installations with
higher capacity lift
30
73%
25
61%
21
53% 19
20
15
14
41%
29%
10
6
5
1
6
3
34%
7
4
9
6
8
7
4
0
2013
Q3
3Q 2013
2013
4QQ4
2013
2014
Q1
1Q 2014
2014
Q2
2Q 2014
2014
Q3E
3Q 2014
2014
Q4E
4Q 2014
46
Bakken Artificial Lift Optimization
Beating Prior Rod Pump Area Averages
2. Beating the 603 MBoe type curve utilizing ESPs
3. Expanding field boundaries and unlocking value
through enhanced completions and higher
volume artificial lift
1
Cumulative Production (Boe)
1. Maximizing the value of standard completions
using higher volume lift (long stroke unit)
Area Average
50,000
40,000
30,000
20,000
Lift Installed
10,000
0
0
603 MBoe Type Curve
Northern Well (ESP)
80,000
70,000
60,000
50,000
40,000
30,000
20,000
Lift Installed
10,000
0
0
50
Days 100
150
3
Cumulative Production (Boe)
Cumulative Production (Boe)
2
Cecilia 1-27H1 (LSU)
50
Days
603 MBoe Type Curve
60,000
100
150
Exploration Well (GL)
50,000
40,000
30,000
20,000
Lift Installed
10,000
0
0
25
Days 50
75
100
47
Optimized Water Handling: LOE Reduction
Current
Under Construction
Planned
9
2
4
Produced Water
Gathering System
150 miles
175 miles
100 miles
Freshwater
Distribution System
25 miles
25 miles
125 miles
Salt Water Disposal
Wells (SWDs)
• SWDs and produced water gathering systems offer significant cost savings
compared to trucking water to 3rd party facilities
• Currently 45% of produced water is handled at CLR facilities with growing
capacity to support current and future operations
• Freshwater distribution systems provide maintenance water to existing wells
and low cost freshwater for completions operations
48
Optimized Central Tank Batteries (CTBs)
•
6 CTBs are currently servicing as many as 14 wells each with plans for up to 28 wells per facility
•
Benefits include a smaller footprint, cost savings and flexibility to easily expand for future wells
•
Leveraging success from Cedar Hills
49
Bakken Development Cost Evolution
Bakken Completed Well Cost ($MM)
$12M
Operational efficiency leads to
reduced well cost
Cost reduction allows for
completions testing
Encouraging enhanced
completions results drive
optimization testing
$0.6
$10M
$1.6
$1.2
$9.2
$9.4
$0.2
$8M
$8.0
$10.0
$7.8
$6M
$4M
$2M
$0M
2012
2013
1st Half 2014
2nd Half 2014
50
Putting It All Together to Maximize Profitability
“Ears Back” in Antelope
Gross Average Quarterly
Production (Boe per day)
14,000
Keys to Development
• One of the highest rate of return areas
• Impressive EURs (700-1,000+ MBoe)
12,000
10,000
8,000
6,000
4,000
2,000
0
• 41 wells currently drilling / completing
Boe per day
3Q12 4Q12 1Q13 2Q13 3Q13 4Q13 1Q14 2Q14 3Q14
• 3-5 rigs actively drilling
• 350-400 total wells for full development
• Utilizing enhanced completions
• Optimizing lift for higher production volumes
.
51
Southern
Region
Southern Region
Platform for Growth
Production History
Assembling the Leasehold
John Haiduk
Geologic Manager
Mark Fisher
Land Manager
SCOOP: What’s New for Continental?
Rivals the Bakken net resource
potential to CLR
Excellent economics
Springer discovery
in the heart of SCOOP
• 3.6 Billion Boe net unrisked resource potential to CLR
• Bakken-or-better RORs
• New oil play: 118,000 net acres oil, 77,000 net acres
condensate/gas
Woodford EUR per well
increased
• Extended laterals
Density projects already
underway
• 1 producing, 3 drilling
Leasehold +176% since
2012 Investor Day
• 471,000 net acres
Optimizing operations
• Increasing rig count and accelerating development
54
SCOOP: Another Large Platform for Growth
Unrisked Resource Potential Rivals the Bakken
3.6 Billion Boe net unrisked resource
potential
•
•
3.6
320% over Investor Day 2012
4,744 net unrisked drilling locations
–
–
–
+326% over Investor Day 2012
80% operated
30 years of operated inventory (30 rigs)
7,000
3.5
6,000
3.0
5,000
646,000 net combined (Woodford/Springer)
resource leasehold acreage
–
4.0
471,000 net acre leasehold in SCOOP, which contains
a 451,000 net acre leasehold in Woodford and a
195,000 net acre leasehold in Springer Shale ⁽²⁾
Net Resources, Billion Boe
–
8,000
Well Count
•
Unrisked Drilling Inventory
and Net Resource Potential⁽¹⁾
2.5
4,744
4,000
2.0
3,000
1.5
2,000
1.0
1,000
0.5
0.0
0
Net Wells
1
Net Resource
2 Potential
Proved Undeveloped Reserves
(1) Based on 80% NRI and 120 to 320 acre spacing
(2)
The Springer Shale leasehold contains ~20,000 net acres which is only prospective for the Springer Shale, and
does not include the Woodford.
55
SCOOP: Rapid Production Growth
Woodford & Springer
• ~34,300 Boe per day average
in 2Q14
• 96 Non-operated wells, +75
wells since Investor Day 2012
35,000
70
CLR Rig Count
30,000
60
25,000
50
20,000
40
30
15,000
18
10,000
6
6
7
Investor Day Q3
2012
Q4
Q1
2013
5,000
0
7
9
Q2
21
23
20
11
10
Q3
Q4
Q1
2014
Q2
0
CLR Rig Count
• 112 CLR-operated wells, +86
wells since Investor Day 2012
80
SCOOP (62% Liquids)
Net Boe per day
– 46% Oil, 74% total liquids
– 2Q14 exit rate of ~36,300
Boe per day
Net Daily Production
40,000
56
CLR: SCOOP’s #1 Leasehold Owner
•
•
•
•
Early entrant advantage
Timely recognition of play concept
Play confirmation through initial delineation
success
Dominant leasehold position in both the oil
and condensate fairways with ongoing leasing
and acquisition initiatives
Net Leasehold Growth
500,000
471,000 net acres of leasehold
471,000
Net Acres
400,000
300,000
200,000 170,600
100,000
0
Inv. Day
2012
3Q12
4Q12
1Q13
2Q13
3Q13
4Q13
1Q14
2Q14
9/18/2014
57
Teamwork Drives Results with Land
Progress since 2012 CLR Investor Day
• Acquisitions
– 153 acquisitions (16,531 oil and gas leases)
Leasehold Acquired By:
2%
• Extensive fee leasing
– 16,382 oil and gas leases
• Challenges to entry…it is not for everyone
– Title complexity
• Average lease size: 8 net acres
• Historic production with depth severed
leasehold
48%
50%
– Massive internal and external manpower
investment
Acquisitions
Leasing
Poolings
58
Woodford Overview
An Area with Vast Legacy Oil Production
High Quality Reservoir Characteristics
Andy Rihn
Senior Exploration Geologist
The Perfect Recipe for Long-Term Success
SCOOP Woodford Overview
•
A long legacy of oil production
–
–
•
Oklahoma City
Woodford: primary source rock for the
conventional reservoirs
–
•
3.2 billion barrels of oil conventionally produced
from 60 reservoirs
3 of the top oil-producing counties in Oklahoma
Vast majority of the oil generated remains in the
Woodford
Woodford key components
–
–
–
–
–
Thickness: 100-950’
TOC: 4-10%
Superior porosity / permeability
Brittleness: natural and induced fractures
Basin-centered: over-pressured (up to 0.7 psi/ft)
Industry wells
CLR leasehold
15 Mi.
60
Woodford Update
•
SCOOP Industry Activity Map
Developing and expanding
2014
2013
2009
2011
2010
2012
– ~45% De-risked
•
Increasing EUR/well with extended laterals
•
Distinct oil, condensate and gas fairways
De-risked
Hansell
– Top CLR oil fairway producers:
•
•
Chalfant
Hansell IP: 973 Boe per day (90% Oil)
Simms IP: 809 Boe per day (83% Oil)
– Top CLR condensate fairway producers:
•
•
•
•
Claudine IP: 18.1 MMcfe per day (8% Oil)
Chalfant IP: 16.2 MMcfe per day (13% Oil)
Both state record IPs for 4,500’ and extended laterals
Doubled rig count in the last 12 months
– 19 operated SCOOP Woodford rigs currently
– Planned average 21 rigs in 2015
69 Rigs Active in
SCOOP
Claudine
Simms
Expanding
15 Mi.
•
3 density projects underway
‒ 1 producing: BEAN
‒ 2 drilling: Poteet and Good Martin
•
1,100 square miles of 3D seismic data
New
Hz Hz.
2014WDFD
Woodford
WDFD
Hz Hz.
Woodford
CLR Acreage
Oil Fairway
Condensate Fairway
Gas Fairway
61
Woodford Thickness Expands Across Leasehold
2013 – 2014 Exploratory Program
Development Program Initiated
North
130’
150’
Hunton
245’
South
380’
560’
W
o
o
d
f
o
r
d
950’
230’
295’
465’
Hunton
Gamma Ray
Brittleness
25 Mi.
62
The SCOOP Woodford:
Condensate Fairway
Extended Laterals
Well Economics
BEAN and Poteet Density Projects
Candace Cantrell
Senior Reservoir Engineer
Woodford: Condensate Fairway
10,000:1 – 100,000:1 gas/oil ratio
•
CLR unrisked resource potential
Oklahoma City
– 2.0 net Billion Boe
•
CLR unrisked drilling locations
– 1,554 net operated locations
– 775 net non-operated locations
•
206 industry wells producing
– 87 CLR operated wells
•
223,000 net acres
15 Mi.
•
15 rigs estimated for 2015
CLR Woodford Hz
Industry Woodford Hz
CLR Acreage
Oil Fairway
Condensate Fairway
Gas Fairway
64
Higher Returns With Extended Laterals
EUR: 1,725 MBoe
•
•
•
1,600
Normalized to 7,500’ lateral
Completed well cost: $12.2 MM
ROR: ~75% at $90/$4 prices
Extended laterals: ~70% added resource
for ~40% added cost
̶
̶
Plan to drill 10,000’ laterals where possible:
lateral length of future locations expected to
average 7,500’
Extended laterals allow access to 600’-900’ of
reservoir previously not drilled due to setback
and drilling requirements for 640 acre spacing
Condensate Fairway
(53% Liquids)
Oil
13%
Gas
47%
1,400
1,200
240
210
180
1,000
150
800
120
600
90
400
60
200
30
0
0
0
6
12
18
24
Producing Months
7,500'
Oil IP Rate, Bbl/day
Oil Initial Decline
280
1.1
Oil EUR, MBo
295
Gas b factor
7,000
58%
1.2
Gas EUR, MMcf
8,580
Equivalent EUR, MBoe
1,725
Minimum Decline
Lateral Length, ft
Capital, $MM
36
130%
61%
Oil b factor
Gas Initial Decline
30
Condensate ROR vs Gas Price
Condensate Type Curve Data
Gas IP Rate, Mcf/day
NGL
40%
270
4,500' Act. Well Count
Ext. Act. Well Count
4,500' Act. Production
Ext. Type Curve (Normalized to 7,500' LL)
Ext. Act. Production (8,700' Avg LL)
6%
7,500'
12.2
110%
ROR
̶
Boe per day
•
Condensate Fairway Type Curve
1,800
Well Count
Woodford Condensate Fairway
90%
70%
50%
Oil Price: $90/BBL
30%
$2
$3
$4
$5
Natural Gas Price, $/MCF
$6
Oil Differential: -2.3%, Gas Differential Premium: +38%
65
Early Success at BEAN Density Project
Woodford Condensate Fairway
4 well project
–
–
–
–
–
–
•
•
Combined IP: 8,300 Boe per day
Project EUR: 7,428 MBoe
4,500’ laterals
2 wells upper Woodford, 2 wells lower
Woodford
660’ spacing between wellbores
Recorded micro-seismic
Performance supports drilling up to 8
wells per DSU
Accelerated learning—leveraging
Bakken experience
2,000
1,500
1,000
500
0
0
1
2
3
4
5
6
Producing Months
7
8
9
10
Top View
Arrington
Upper Woodford
•
Bearden 1-25H (4,500')
Eula Mae 1-26H (4,500')
Arrington 1-23H (4,500')
Newy 1-24H (4,500')
(2012) 4,500' Type Curve
Newy
1 MILE
1 MILE
UPPER
UPPERWOODFORD
WOODFORD
Eula Mae
Upper Woodford
–
Bearden, Eula Mae, Arrington and
Newy wells
Average interest: 84% WI, 68% NRI
Lower Woodford
–
Lower Woodford
B.E.A.N. Project, SE Grady County
Boe per day (Avg. 54% liquids)
•
BEAN Density Test
2,500
Bearden
660’
~150’
LOWER WOODFORD
LOWER
WOODFORD
66
Poteet Density Project Underway
•
Poteet Unit, NE Stephens County
–
–
•
Within 5 miles of BEAN density test
Average Interest: 94% WI, 76% NRI
10 well density – now drilling
–
–
–
–
–
Drilling 95% complete
Dual horizon (upper and lower
Woodford)
1,026’ interwell spacing (same horizon),
513’ offset
7,500’ laterals
Simultaneous stimulation
•
1st sales expected late 4Q 2014
•
2 additional density projects planned for
2015 in the condensate fairway
Boe per day (50% total liquids)
Woodford Condensate Fairway
Parent Well: Poteet 1-17H
1,800
1,600
1,400
1,200
1,000
800
600
400
200
0
Poteet 1-17H (4,500' Lateral)
(2012) 4,500' Type Curve
0
6
12
18
24
Producing Months
30
36
2014 Full-Scale
Density Project
UPPER WOODFORD
LOWER WOODFORD
Existing Well
New Wells
67
The SCOOP Woodford:
Oil Fairway
Extended Laterals
Good Martin Density Project
Dan Harms
Resource Development Manager
Woodford: Oil Fairway
<10,000:1 gas/oil ratio
• CLR unrisked resource potential
Oklahoma City
– 615 net MMBoe
• CLR unrisked drilling locations
– 946 net operated locations
– 473 net non-operated locations
• 312 industry wells producing
– 25 CLR operated wells
• 169,000 net acres
• 6 rigs estimated for 2015
15 Mi.
CLR Woodford Hz
Industry Woodford Hz
CLR Acreage
Oil Fairway
Condensate Fairway
Gas Fairway
69
Unlocking the Woodford Oil Fairway
EUR: 655 MBoe
•
•
•
Normalized to a 7,500’ lateral
Completed well cost: $12.2 MM
ROR: ~30% at $90/$4 prices
Extended laterals: ~70% added resource
for ~40% added cost
̶
̶
Plan to drill 10,000’ laterals where possible: lateral
length of future locations expected to average
7,500’
Extended laterals allow access to 600’-900’ of
reservoir previously not drilled due to setback and
drilling requirements for 640 acre spacing
Oil Fairway
(83% Liquids)
Gas
17%
NGL
26%
Oil
57%
120
Act. Well Count
Ext. Act. Well Count
Act. Production (4,100' Avg LL)
Ext. Type Curve (Normalized to 7,500' LL)
Ext. Act. Production (9,500' Avg LL)
500
400
100
80
300
60
200
40
100
20
0
0
0
6
12
Oil Type Curve Data
7,500'
Oil IP Rate, Bbl/day
Oil Initial Decline
Oil b factor
Oil EUR, MBo
Gas IP Rate, Mcf/day
Gas Initial Decline
Gas b factor
Gas EUR, MMcf
Equivalent EUR, MBoe
Minimum Decline
Lateral Length, ft
Capital, $MM
400
18
24
Producing Months
50%
30
36
Oil ROR vs Oil Price
59%
1.1
40%
440
780
49%
1.3
1,290
655
6%
7,500'
12.2
ROR
̶
Boe per day
•
Oil Fairway Type Curve
600
Well Count
Woodford Oil Fairway
30%
20%
Gas Price: $4/MCF
10%
$70
$80 $90 $100 $110 $120
Oil Price, $/BBL
Oil Differential: -2.3%, Gas Differential Premium: +38%
70
Good Martin Density Project Underway
Woodford Oil Fairway
Good Martin Unit, Grady County
–
–
•
•
1st CLR oil fairway infill
8-well density – now drilling
–
–
–
–
–
–
•
•
Offsetting the Hansell well
Average interest: 66% WI, 53% NRI
Drilling 70% complete
Single horizon
660’ spacing between wellbores
7,500’ laterals
Simultaneous stimulation
Planned microseismic
Boe per day ( 71% Oil )
•
Parent Well: Hansell 1-3-34XH
1,400
Hansell 1-3-34XH (9,800' Lateral)
1,200
Extended Type Curve (Normalized to 7,500' LL)
1,000
800
600
400
200
0
0
1
2
3
2015 Full-Scale
Density Project
4
5
6
7
Producing Months
330’
8
1320’
9
2640’
660’
1st sales expected in 1Q 2015
2 additional density projects
planned for 2015 in the oil fairway
10
11
12
1320’ 330’
UPPER WOODFORD
LOWER WOODFORD
1 MILE
Wells
71
Woodford: Dry Gas Fairway
Dan Harms
Resource Development Manager
Dry Gas Fairway
Woodford
>100,000:1 gas/oil ratio
•
CLR unrisked resource potential
–
•
Oklahoma City
3.2 Tcfe (528 net MMBoe)
CLR unrisked drilling locations
–
–
509 net operated locations
73 net non-operated locations
•
59,000 net acres
•
Leased primarily for Springer Shale
potential
•
Provides future opportunity and
optionality on higher gas prices
–
–
Currently limiting capital allocation
Focusing on higher returns in the condensate
and oil fairways
15 Mi.
CLR Acreage
Oil Fairway
Condensate Fairway
Gas Fairway
73
Southern Operations
Drilling Efficiencies
Completions Updates
Corey Russell
Drilling Manager
Scott Donnelly
Completion Manager
Drilling Efficiency Improving During Delineation
SCOOP Woodford
• Shift to extended laterals
• Optimizing operations
- Fit for purpose rig fleet
- Applying rotary steerable when
optimal
- Improving bit and motor technology
applications
- Utilizing improvements in drilling
hydraulics
4,500' Lateral
Extended Lateral
75%
% of Well Count
- Yielding lower drilling costs
- ~50% decrease in $/lateral foot,
based on average 9,128’ lateral
Shift to Longer Laterals
100%
50%
25%
0%
1Q13
2Q13
3Q13
4Q13
1Q14
2Q14
YE14
Avg Drilling $/Lateral Ft
$1,500
$1,250
$1,000
• Rigs contracted to execute 2015 plan
$750
$500
1Q13
2Q13
3Q13
4Q13
1Q14
2Q14
YE14
75
Drilling: Managing Costs During Rapid Growth
SCOOP Woodford
2014 Completed Well Cost Target of $12.2 MM for 7,500’ Lateral
SCOOP Woodford Average Completed Well Cost:
$20
20
18
16
Millions
$14.0
$13.7
Avg. Lateral
8,000’
$12
$9.9
Avg. Lateral
9,100'
$9.1
14
12
10
$9.1
Rig Count
$16
8
$8
6
4
$4
2
0
$0
2012
2013
4,500' Lateral
Extended Lateral
1H14
Woodford Rig Count
76
Completions: Managing Costs During Rapid Growth
SCOOP Woodford
• Leveraging purchasing power
–
–
Leader, dominant operator in the play
Capitalizing on economies of scale
Stimulation size and cost per stage
228
–
$140
Produced water recycling lowering system cost for
water supply and disposal
Ongoing infrastructure projects being considered
and negotiated to accommodate future market
capacity
2012
2013
Stim cost/stg (m$)
YTD 2014
Stim size/stg (m-lbs.)
Days from rig release to first production
70
57
• Technology expanding the play
–
–
–
$139
Dedicated stimulation and wireline crews
Consistent, repeatable operations
• Expanding infrastructure
–
235
$193
• Lowering cycle times
–
–
213
51
Drilling deeper targets
Longer laterals
Larger treatments
2012
2013
YTD 2014
77
Springer Shale Discovery
Revealing Stealth Play
Great Economics
Hartley Unit
Will Parker
Senior Exploration Geologist
Jennifer White
Senior Petrophysicist
Dan Harms
Resource Development Manager
Corey Russell
Drilling Manager
Announcing CLR’s Newest Oil Discovery: Springer Shale
•
Incremental value created from in-house
exploration
Chesterian
Osagean Meramec
Compounds value as resource was already leased
for Woodford
Middle Upper
•
Atoka Sands
Morrow Sands
Springer Shale
Discovery!
Caney Shale
Sycamore Limestone
Woodford Shale
Ulsterian
• 118,000 net acres in the oil fairway
• 77,000 net acres combined in the gas/condensate
fairways
Deese Sands
Springer Sands
Mississippian
– 195,000 net acres today, up ~540% since 2012
Investor Day
Morrowan Atokan Des Moinesian Missourian
Reservoir in the heart of SCOOP
Devonian
•
Cayugan
– 127 net MMBoe oil fairway
– 320 net MMBoe, or 1.9 Tcfe, combined in the
gas/condensate fairways
Hoxbar Sands
Hunton Limestone
Niagaran
447 MMBoe net unrisked resource potential to CLR
Silurian
•
Pennsylvanian
2012 Stealth Play Becomes Reality
79
Springer Shale Oil Fairway
CLR: KL Fulton 1-21H
•
IP: 2,122 boepd
118,000 net acres in the oil fairway
–
–
46,000 net acres derisked by 11 producers and
Woodford well control
72,000 net acres of additional upside, currently
testing
SCOOP
CLR: Birt 1-13H
IP: 793 boepd
Oct. 2013
CLR: Wilkerson 1-20H
CLR: Gala 1-22H
IP: 2,038 boepd
IP: 765 boepd
Jan. 2013
CLR: Sweet 1-2H
•
127 MMBoe net unrisked recoverable resource
potential from 46,000 net derisked acres
–
215 net locations
• 188 net operated locations
• 27 net non-operated locations
–
–
•
CLR: Burkes 1-28H
IP: 593 boepd
CLR: Lynn 1-13H
IP: 1,897 boepd
CLR: Scott Trust 1-15H
IP: 403 boepd
CLR: Ball 1-19H
IP: 1,037 boepd
67% oil, 84% liquids in fairway
80-320 acre spacing/20% recovery factor
Apr. 2013
CLR: Anne 1-11H
IP: 848 boepd
CLR: Robert Jo 1-8H
IP: 1,429 boepd
Successful exploration
–
–
–
–
•
IP: 597 boepd
Discovery well: Wilkerson 1-20H (Jan. 2013)
Delineation well: Ball 1-19H (Apr. 2013)
Confirmation well: Birt 1-13H (Oct. 2013)
2014: continued confirmation program
Significant resource potential upside
–
First density pilot drilling (128-acre spacing)
Springer
Fairway
12 Miles
SCOOP Outline
CLR 2013 Key Wells
Springer Fairway
CLR Springer Shale Completions
CLR Leasehold
CLR Springer Shale Wells WOC
80
Repeatability Confirmed by 11 CLR Producers
Springer Shale Oil
CLR Operated Springer Shale Wells
2,200
2,000
Wilkerson 1-20H: Discovery Well
Ball 1-19H: Delineation Well
Birt 1-13H: Confirmation Well
P
< 90 Days on production
940 MBoe EUR Type Curve (4,500')
1,800
Boe per day
1,600
1,400
1,200
1,000
800
600
400
200
0
0
2
4
6
• Results from 11 CLR operated wells
–
–
–
•
30 day avg. IP: 700 Boe per day
Avg. 4,037’ laterals
Avg. 83% WI
August Springer Shale production
averaged 3,629 net Boe per day
8
10
Producing Months
12
Well
Wilkerson 1-20H
Ball 1-19H
Birt 1-13H
14
16
IP
Current Rate
Boe per day Boe per day
2,038
1,037
793
363
290
225
18
20
Cumulative
Production
293 MBoe (20 mos)
229 MBoe (16 mos)
114 MBoe (11 mos)
81
Springer Shale Oil
EUR/Well Model: 940 MBoe
Completed well cost: $9.7 MM
ROR: >100% at $90/$4 prices
Type curve based on wells with > 30 days of
production
•
First extended lateral to be drilled in 4Q14
•
Delineation and density testing underway
–
–
3 rigs currently drilling delineation
5 rigs on infill pilot
600
20
400
300
200
10
100
0
0
0
6
12
18
24
Producing Months
4,500'
(84% Liquids)
Gas
16%
NGL
17%
Oil
67%
Oil IP Rate, Bbl/day
Oil Initial Decline
Oil b factor
Oil EUR, MBo
Gas IP Rate, Mcf/day
Gas Initial Decline
Gas b factor
Gas EUR, MMcf
Equivalent EUR, MBoe
Minimum Decline
Lateral Length, ft
Capital, $MM
670
180%
62%
160%
1.25
867
120%
1.4
100%
1,230
80%
940
6%
4,500
9.7
36
140%
735
56%
30
Oil ROR vs Oil Price
Springer Shale Type Curve
Springer Shale Fairway
30
500
ROR
–
40
Well Count
Type Curve (Normalized to 4,500' LL)
Act. Production (4,066' Avg LL)
700
Boe per day
•
•
•
Springer Shale Type Curve
800
Well Count
Exceptional Economics
Gas Price: $4/MCF
60%
$70
$80 $90 $100 $110 $120
Oil Price, $/BBL
Oil Differential: -2.3%, Gas Differential Premium: +38%
82
CLR Research Identifies Springer Shale Resource Reservoir
Middle Osagean Meramec Chesterian Morrowan Atokan Des Moinesian Missourian
Upper
Cayugan Ulsterian
Niagaran
Mississippian
Devonian
Silurian
Hoxbar Sands
Gamma Ray
Resistivity
Deese Sands
105’
Pennsylvanian
Exploration Success Drives Incremental Value
Atoka Sands
Morrow Sands
Springer Sands
Springer Shale
Caney Shale
SEM Photo – Kerogen Porosity
Sycamore Limestone
Woodford Shale
Hunton Limestone
Proprietary data:
• 2 whole cores
• Dozens of sidewall cores
• Play-wide petrophysical
analysis
• Rock mechanics studies
• SEM ion milling
Key observations:
• Up to 150’ thick
• Highly siliceous
• Organics rich
• Low clay
• Great porosity & permeability
• Over-pressured
• Excellent stimulation
containment
Porosity
83
First Density Project Underway: Hartley Unit
Springer Shale Oil
•
Hartley Unit, Grady County
–
Average Interest: 87% WI, 70% NRI
•
Offsets Wilkerson discovery well
•
5-well density – now drilling
–
–
–
1,055’ spacing between wellbores
4,500’ laterals
Simultaneous stimulation
Hartley
Density
Project
Springer
Fairway
12 Miles
CLR 2013 Key Wells
CLR Leasehold
CLR Springer Shale Completions
330’
1320’
2640’
1st sales expected in 1Q 2015
1055’
•
3 additional density projects
planned for 2015 in the Springer
fairway
1320’
330’
SPRINGER
•
SCOOP
1 MILE
Proposed Wells
84
Gas/Condensate Fairway
Springer Shale
•
–
•
1.9 Tcfe (320 net MMBoe)
CLR unrisked drilling locations
–
–
182 net operated locations
17 net non-operated locations
•
77,000 net acres
•
Provides future opportunity and
optionality on higher gas prices
–
–
•
SCOOP
CLR unrisked resource potential
Springer
Fairway
Currently limiting capital allocation
Focusing on higher returns in the Springer
Shale oil fairway
Oil to liquids-rich contacts needed to
determine exact fairways, undetermined
at this point leaving additional upside for
greater condensate value
12 Miles
SCOOP Outline
Springer Fairway
CLR Acreage
85
Already Realizing Drilling Efficiency Gains
Springer Shale Oil
̶
Operational improvement as activity
grows
Yielding lower drilling costs
36% decrease in days on well
̶
1-mile lateral
80
• Optimizing Springer Shale drilling
program
60
40
20
0
Applying the latest technology
Managing dynamic drilling hydraulics
Utilizing advanced earth modeling
Optimizing wellbore design
2012
2013
YTD 2014
Springer Shale CWC
$16
10
8
$12
Millions
̶
̶
̶
̶
Springer Shale Spud to Rig Release
6
$8
4
$4
$-0
2
0
2012
2013
CWC
(1)
Rig Count
̶
100
Days
• Rapid knowledge gain
YTD 2014
Springer Rig Count
YTD 2014 figures include complet ions cost estimates for recently drilled wells
86
Southern
Resource Potential
John Haiduk
Geologic Manager
CLR’s Upside: Southern Unrisked Resource
Benefit of Stacked Plays
Net
Acres⁽¹⁾
Potential Net
Wells
Net Unrisked
Resource Potential
(MMBoe)
9,000
27
4
Springer
195,000
414
447
Caney
70,000
430
160
Meramec
“STACK”
102,000
454
507
NW Cana Woodford
45,000
360
475
Woodford
451,000
4,330
3,143
Hunton
13,000
20
30
Totals
885,000
6,035
4,766
Penn. Sands
(1) Acreage total is for combined resource prospective areas.
88
New Ventures
Exploration
New Ventures
Exploration Driven
Commitment to Innovation
Tony Barrett
Geologic Manager
CLR – Exploration Driven
Organic Growth Through Science, Technology, and Innovation
Focus on Unconventional Reservoirs
Bakken, MT
• City of Enid wells—OK (1984)
Bakken/Three Forks, ND
Red River
• CLR shifts to oil (1985)
• Ames Hole—OK (1991)
• Red River⁽¹⁾—ND (1995)
• Bakken—MT (2003)
• Bakken⁽²⁾/Three Forks—ND (2004)
Ames Hole
Anadarko Woodford
• Arkoma Woodford—OK (2006)
City of Enid Wells
Arkoma Woodford
SCOOP: Woodford
and Springer
• Anadarko Woodford—OK (2008)
• SCOOP Woodford—OK (2012)
• SCOOP Springer—OK (2013)
( 1 ) F i r s t o i l f i e l d i n t h e U . S . t o b e d e v e l o p e d e x c l u s i v e l y w i t h h o r i zo n t a l d r i l l i n g
(2) Drilled first commercially successful well in the North Dakota Bakken to be both
h o r i zo n t a l l y d r i l l e d a n d f r a c t u r e s t i m u l a t e d
91
Growing our Exploration Portfolio
Investor and Analyst Day 2012
Active Exploration Projects
2014 Active Exploration Projects
Project
Expected
Product
CLR Net Acres
Project
Expected
Product
CLR Net Acres
Stealth A
Gas/Oil
5,000
Stealth 1
Oil
30,000
Stealth B
Gas/Oil
8,970
Stealth 2
Gas/Oil
140,000
Stealth C
Oil
30,500
Stealth 3 (New)
Oil/Gas
130,000
Stealth D
Oil/Gas
17,200
Stealth 4 (New)
Oil
15,000
Stealth E
Oil
25,000
Stealth 5
Oil
153,000
Stealth F
Gas/Oil
23,500
Stealth 6 (New)
Gas/Oil
54,000
110,170
Stealth 7
Oil
17,000
2012 Total Leasehold
2014 Total Leasehold
539,000
5X growth in leasehold position in two years!
92
Continental’s Commitment to Exploration and
Innovation Continues
• Committed to organic growth through the drill bit in our core areas and in our
New Ventures Exploration programs
• Continuously adding the right staff and experience to grow our exploration
programs
̶
̶
2012: 8 total New Ventures Exploration staff
2014: 24 total New Ventures Exploration staff
• Currently pursuing seven New Ventures projects with >500,000 net acres of
committed leasehold outside of our core areas
• 100% of all new projects are horizontal targets in unconventional reservoirs
• Always enhancing our technical understanding of unconventional plays with
the acquisition of advanced data sets and analysis
93
Finance
Financial Strategy
Financial Update
Supporting Strong Margins
Capital Efficiency
Budget
2014-2015 Guidance
John Hart
Senior Vice President,
CFO and Treasurer
Financial Strategy
• Financial framework built for long-term value generation:
– Strong entrepreneurial spirit
– Exploration-focus
– Leader in oil and liquids focused asset basins
• Maintain production mix of 68% to 70% oil in each year of five year plan
• 80+% liquids when including natural gas liquids
• Exceptional, disciplined growth with multi-decade oil-weighted inventory
• Investment grade, pure-play E&P company
– Low leverage
– Ample liquidity and flexibility
– Industry leading financial metrics
96
YTD Operational & Financial Highlights
•
2Q14 production of 167,953 Boe per day
–
•
•
On track to achieve 27% to 30% growth for 2014
–
Mid-year 2014 proved reserves: 1.2B Boe •
–
Up 31% over mid-year 2013
1H 2014 EBITDAX of $1.6B
Up from $1.3B (24%) for 1H 2013
Marketing strategy and opex focus drive
strong cash margin
–
75% cash margin ($55.84 per Boe) for 1H 2014
Production (Boe per day)
EBITDAX ($MM)
180,000
167,953
160,000
120,000
$2,000
$1,500
80,000
61,865
60,000
37,324
$1,643
$1,304
$1,000
43,318
$811
$500
20,000
0
$2,840
$1,963
97,583
100,000
40,000
2Q EBITDAX
1H14 EBITDAX
FY EBITDAX
$2,500
135,919
140,000
$3,000
$708
$451
2009
2010
2011
2012
2013
2Q 2014
$0
2009
2010
2011
2012
2013
$868
2Q14
1H14
See appendix for reconciliation of net income and operating cash flows to EBITDAX.
97
Oil & Gas Marketing: Supporting Strong Margins
•
Significant takeaway, gathering and processing infrastructure exists in the Bakken
and SCOOP with additional expansion underway
– Bakken
• New long-haul pipe to be in service 2H14 (Pony Express) with additional pipeline
additions expected
• Continued portfolio approach to maximize value
– SCOOP
•
•
•
•
Embedded regional gathering system in place
100+ HP of new gathering compression facilities being added in 2014 and 2015
100+ miles of header/expansion pipe to be in place by YE2014
Enable currently constructing incremental ~1Bcf per day of SCOOP processing capacity by
March 2017
•
Continental is well positioned with a competitive advantage in our primary plays
due to the scale of our operations
•
Strong corporate focus on marketing to generate strong margins; among industry
leaders
98
Cost Discipline Driving Excellent Margins
($ per Boe)
$80
• Strong/stable cash
margins(1)
$70
$60
$50
$40
$30
Cash
Margin
$53.52
Cash
Margin
$55.45
Cash
Margin
$55.84
74%
74%
75%
75%
$3.95
$2.38
$5.58
$4.74
$2.07
$6.02
$4.74
$2.08
$4.73
$2.24
$6.32
$6.10
$5.49
$5.69
$5.50
$5.62
2012
2013
2Q2014
1H2014
Cash
Margin
$48.59
$20
$10
$0
Production Expense
P/S Tax & Other
G&A(2)
Interest
• Margin scales as costs
remain flat
• Strong oil price and
cost focus continues
to drive excellent
margins
Cash Margin
(1) See “Continuing to Deliver Excellent Margins” in the Appendix for the method of calculating cash margin..
(2) Excludes G&A related to Equity based compensation and relocation expense.
99
Capital Efficiency
Recycle Ratio – Industry Leader⁽¹⁾
Gas weighted(2)
Oil weighted
• Recycle Ratio = Cash margin/3 yr F&D per Boe
5.0x
• Exploration leadership enables low finding and development costs
4.5x
4.5x
4.2x
• Efficient operator - evidenced by low operating costs per Boe
4.0x
4.0x
• Oil and liquids focused, generating high margins
3.5x
3.3x
3.0x
2.7x
2.4x
2.5x
2.3x
2.1x
2.0x
1.5x
1.5x
0.9x
1.0x
0.8x
0.5x
0.2x
0.0x
CLR
RRC
COG
DNR
KOG
CXO
Avg Large Cap Peers
APC
WLL
SD
CHK
DVN
PXD
Avg Small/Mid Cap Peers
(1) Source: KeyBanc, 8/11/2014
(2) Source: KeyBanc, 8/11/2014 – “Gas weighted” are those peers whose 2013 YE Reserves are
greater than 50% gas
100
2014 Production Growth vs Market Cap
80%
Lower Market
Capitalization
YoY Production Growth(1)
70%
CLR 2012
60%
50%
CLR 2014
27% to 30% Growth(2)
$27B to $30B Market cap
AREX
40%
KOG OAS
CLR 2007
17% Growth
$4B Market cap
30%
NFX
20%
COG
XEC
WLL
CLR 2010
CLR 2007
SWN
NBL
MUR
MRO DVN
QEP
$0
$10
1)
2)
APC
PXD
CHK
LPI
SD
0%
RRC
EQT
CXO
SM
UPL DNR
10%
CLR 2014
$20
$30
Market Cap($B)(1)
APA
$40
For companies other than CLR, based on 08/28/14 Market Cap and Consensus Estimates for 2014
production growth
CLR 2014 updated guidance
$50
Lower
Growth
$60
101
3.8x
4.4x
4.7x
MRO
6.0x
CHK
4.7x
6.1x
DVN
APA
6.2x
NFX
5.0x
6.2x
QEP
AREX
6.5x
OAS
6.0x
5.7x
6.5x
6.8x
DNR
SWN
7.0x
SD
6.7x
7.0x
WLL
EOG
7.2x
7.5x
KOG
XEC
7.6x
UPL
8.7x
LPI
7.9x
8.8x
9.7x
CLR
9.0x
CXO
9.9x
COG
10.5x
12.3x
PXD
3.0x
$10Bn+ Market Cap & 15%+ Production CAGR
MUR
SM
APC
NBL
EQT
-
RRC
Enterprise Value / 2014E EBITDAX
12.0x
2X Multiple Compression Strong Stock Price Catalyst
CLR 2015 multiple at 7.9x
CLR
11.5x
12.5x
13.5x
FANG
ATHL
13.6x
15.0x
AR
CLR Valuation
Industry Competitors
Source: Company filings, research reports, and FactSet as of 9/5/14. As prepared by Bank of America Merrill Lynch
102
Strong Liquidity and Financial Profile
Financial Ratios and Ratings
Agency
Net Debt/2Q Annualized EBITDAX⁽¹⁾⁽²⁾
1.55x
Leveraged Cash Margin (1H14)⁽³⁾
$55.84
Moody's
Baa3
Net Debt/June 30 Proved Reserves(1)
$4.47
3 Year All-in F&D ($/Boe) (YE13)
$12.61
S&P
BBB-
$30,351 3 Year Avg. Recycle Ratio (YE13)
4.5x
Net Debt/June Daily Production(1)
Investment Grade
Debt Maturities Summary
2500
5%
2000
($MM)
Credit Ratings
4.5%
1500
1000
500
Undrawn
No maturities in
five year plan
$1,750
7.375%
$200
2014
2015
2016
2017
2018
4.9%
$1,500
7.125%
0
3.8%
$2,000
$1,000
$400
2019
2020
2021
2022
Credit
Facility
06/30/14
Callable
10/1/2015
Callable
4/1/2016
Callable
3/15/2017
(1) Pro forma for 7/11/14 redemption of $300 million of 8.25% senior notes due 2019.
(2) See appendix for reconciliation of net income and operating cash flows to EBITDAX.
(3) See “Continuing to Deliver Excellent Margins” in the Appendix for the method of calculating cash margin.
2023
2024
$700
2044
103
Track Record of Success
9%
CLR Bond Yield
BB Index YTW
BBB Index
8.375%
8.360%
Investment Grade
7.500%
8%
7.125%
6.900%
7%
6.460%
6.070%
5.330%
6%
May 2014
Inaugural IG
Offerings
10 Year 3.8% ($1B)
30 Year 4.9% ($700mm)
5.000%
5.180%
4.500%
5.000%
5%
4.240%
4.625%
4.490%
4.350%
3.843%
4.060%
4%
3.720%
3.330%
$685MM equity offering in March 2011
3%
CLR Ratings:
3.560%
Sep-09
Mar-10
Sep-10
Mar-12
Aug-12
Apr-13
$300 MM
$200 MM
$400 MM
$800 MM
$1.2 B
$1.5 B
$1.0 B
B1/BB
B1/BB
Ba2/BB+
Ba2/BB+
Ba2/BB+
Baa3/BBB-
B2/BB
Redeemed
July 2014
May-14
104
Five Year Plan Update
MBoe per day
350
300
250
Five Year Plan
Announced in
October 2012
Goal
300 MBoe
Per day by
YE2017
200
150
100
50
98 MBoe
per day
130 MBoe
per day
0
2012
2013
2014
2015
2016
2017
105
On Track to Reach 3X Target 1 Year Early
MBoe per day
350
300
250
200
150
136
100
50
0
Reach 300 MBoe per day
in late 2016
175
98 MBoe
per day
2012
(1)
130
2013
2014
Original 5 Year Plan
(1) Midpoint of guidance range
2015
2016
2017
Updated 5 Year Plan
106
2014 Capital Expenditures Budget
Total Capital Expenditures ($4.55B)
$140 MM
Other
Drilling
Leasehold
$300 MM
• Accelerating 2014 to capture value
Other
$165 MM
• Bakken: Enhanced completions
• SCOOP:
 Springer Oil Development
(~100% ROR) –catalyst for
acceleration
SCOOP
Drilling
$1,095 MM
Bakken
Drilling
$2,850 MM
Expected 2014 Exit Rate ~200,000 Boe per day
Average operated rigs
Net wells
45
375
107
2015 Capital Expenditures Budget
Total Capital Expenditures ($5.2B)
Other
Drilling
$180 MM
Leasehold
$300 MM
SCOOP
Drilling
$1,450 MM
Continuing value acceleration in
Bakken and SCOOP
Other
$240 MM
Average
Operated
Rigs
Bakken Operated
22
204
SCOOP Operated
29
100
Other Operated
2
20
n/a
84
53
408
Outside Operated
Bakken
Drilling
$3,030 MM
Net
Wells
Totals
108
Annual Guidance
2014
2015
27% to 30%
26% to 32%
$4.55B
$5.2B
$5.60 to $6.00
$5.50 to $6.00
8% to 8.5%
7.5% to 8.5%
G&A expense per Boe
$2.00 to $2.50
$2.25 to $2.75
Non-cash equity compensation per Boe
$0.70 to $0.90
$0.75 to $0.95
$20.00 to $22.50
$20.00 to $22.50
($8.00) to ($11.00)
($9.00) to ($11.00)
+$1.00 to $1.50
+$1.00 to $1.50
Income tax rate
37%
37%
Deferred taxes
90% to 95%
90% to 95%
Production growth (YOY)
Capital expenditures (non-acquisition)
Operating Expenses:
Production expense per Boe
Production tax (% of oil & gas revenue)
DD&A per Boe
Average Price Differentials:
NYMEX WTI crude oil (per barrel of oil)
Henry Hub natural gas (per Mcf)
* Bold items above in guidance denote a change from the previous disclosure. This is the first time 2015 guidance has been released.
109
Summary
• CLR has done an outstanding job managing growth
– Industry leading, oil concentrated growth with cost discipline
– Track record of adding value through Exploration
• Bakken
• SCOOP
• Springer
– Strong balance sheet providing strategic flexibility
– Exceptional capital efficiency
– 300,000 Boe per day production by YE 2016 – a year ahead of schedule
under our current 5 year plan
Goal: Rapidly bring value forward while maintaining
Investment Grade balance sheet
110
Continuing to Deliver Excellent Margins
Realized oil price ($/Bbl)
Realized natural gas price ($/Mcf)
Oil production (Bopd)
Natural gas production (Mcfpd)
Total production (Boepd)
2012
$84.59
$3.73
68,497
174,521
97,583
2013
$89.93
$4.87
95,859
240,355
135,919
2Q2014
$92.31
$5.43
116,441
309,074
167,953
1H2014
$91.12
$6.20
111,447
292,847
160,255
EBITDAX ($000's) (1)
$1,963,123
$2,839,510
$867,938
$1,643,345
Average oil equivalent price (excludes derivatives)
$65.99
$72.04
$74.09
$74.53
Production expense
Production tax and other
G&A (3)
Interest
Total cash costs
$5.49
$5.58
$2.38
$3.95
$17.40
$5.69
$6.02
$2.07
$4.74
$18.52
$5.50
$6.32
$2.08
$4.74
$18.64
$5.62
$6.10
$2.24
$4.73
$18.69
Cash margin
Cash margin %
$48.59
74%
$53.52
74%
$55.45
75%
$55.84
75%
Key Operational Statistics (per Boe) (2)
1)
2)
3)
See “EBITDAX Reconciliation to GAAP” in Appendix for a reconciliation of GAAP net income and operating cash flows to EBITDAX.
Average costs per Boe have been computed using sales volumes and exclude any effect of derivative transactions.
Excludes G&A related to Equity based compensation and relocation expense.
111
EBITDAX Reconciliation to GAAP
The following tables provide reconciliations of our net income and operating cash flows to EBITDAX for the periods presented:
In thousands
Net income
Interest expense
Provision for income taxes
Depreciation, depletion, amortization and accretion
Property impairments
Exploration expenses
Impact from derivative instruments:
Total (gain) loss on derivatives, net
Total cash received (paid), net
Non-cash (gain) loss on derivatives, net
Non-cash equity compensation
EBITDAX
$
In thousands
Net cash provided by operating activities
Current income tax provision
Interest expense
Exploration expenses, excluding dry hole costs
Gain (loss) on sale of assets, net
Excess tax benefit from stock-based compensation
Other, net
Changes in assets and liabilities
EBITDAX
2009
372,986
2,551
23,232
6,138
709
2,872
(3,890)
46,050
$ 450,648
$
$
2009
71,338
23,232
38,670
207,602
83,694
12,615
1,520
569
2,089
11,408
450,648
$
2010
168,255
53,147
90,212
243,601
64,951
12,763
$
2011
429,072
76,722
258,373
390,899
108,458
27,920
$
2012
739,385
140,708
415,811
692,118
122,274
23,507
$
2013
764,219
235,275
448,830
965,645
220,508
34,947
2Q2014
1H2014
$ 103,538 $ 329,772
72,841
135,816
60,808
193,675
326,871
599,732
79,316
137,524
11,205
16,018
262,524
302,198
(64,143)
(97,407)
198,381
204,791
14,978
26,017
867,938 $ 1,643,345
130,762
35,495
166,257
11,691
810,877
30,049
(34,106)
(4,057)
16,572
$ 1,303,959
(154,016)
(45,721)
(199,737)
29,057
$ 1,963,123
191,751
(61,555)
130,196
39,890
$ 2,839,510
2010
$ 653,167
12,853
53,147
9,739
29,588
5,230
(3,513)
50,666
$ 810,877
2011
$ 1,067,915
13,170
76,722
19,971
20,838
-(4,606)
109,949
$ 1,303,959
2012
$ 1,632,065
10,517
140,708
22,740
136,047
15,618
(7,587)
13,015
$ 1,963,123
2013
$ 2,563,295
6,209
235,275
25,597
88
-(1,829)
10,875
$ 2,839,510
$
$
2Q2014
1H2014
$ 741,791 $ 1,432,453
1,552
3,104
72,841
135,816
6,822
11,635
2,135
(6,363)
--(1,309)
(11,317)
44,106
78,017
$ 867,938 $ 1,643,345
112