Attached files
| file | filename |
|---|---|
| 8-K - FORM 8-K - C&J Energy Services, Inc. | d330741d8k.htm |
| EX-99.1 - PRESS RELEASE - C&J Energy Services, Inc. | d330741dex991.htm |
 C&J Energy
Services, Inc. Investor Presentation
April 9, 2012
Exhibit 99.2 |
 2
Disclaimer
Forward-Looking Statements
Non-GAAP Financial Measures
Certain statements and information in this presentation may
constitute “forward-looking statements” within the meaning of Section
27A of the Securities Act of 1933, as amended, Section 21E of the Securities Exchange Act of 1934, as amended, and the
Private Securities Litigation Reform Act of 1995. The words “believe,”
“expect,” “anticipate,” “plan,” “intend,” “foresee,” “should,”
“would,” “could” or other similar expressions are intended to identify
forward-looking statements, which are generally not historical in nature. These
forward-looking statements are based on our current expectations and beliefs concerning future developments and their
potential effect on us. While management believes that these forward-looking statements are
reasonable as and when made, there can be no assurance that future developments affecting us
will be those that we anticipate. All comments concerning our expectations for future revenues
and operating results are based on our forecasts for our existing operations and do not include the potential impact of
any future acquisitions. Our forward-looking statements involve significant risks and
uncertainties (some of which are beyond our control) and assumptions that could cause actual
results to differ materially from our historical experience and our present expectations or
projections. Known material factors that could cause our actual results to differ from our projected results are described in our filings
with the Securities and Exchange Commission (“SEC”), including but not limited to our Annual
Report on Form 10-K for the fiscal year ended December 31, 2011.
All readers are cautioned not to place undue reliance on forward-looking statements, which speak
only as of the date hereof. We undertake no obligation to publicly update or revise
any forward-looking statements after the date they are made, whether as a result of new
information, future events or otherwise. We use both GAAP and certain non-GAAP financial measures to assess performance. Generally, a
non-GAAP financial measure is a numerical measure of a company's performance, financial
position or cash flows that either excludes or includes amounts that are not normally excluded
or included in the most directly comparable measure calculated and presented in accordance with GAAP. C&J
management believes that these non-GAAP measures provide useful supplemental information to
investors in order that they may evaluate our financial performance using the same measures as
management. These non-GAAP financial measures should not be considered as a
substitute for, or superior to, measures of financial performance prepared in accordance with GAAP. In evaluating
these measures, investors should consider that the methodology applied in calculating such measures
may differ among companies and analysts. Reconciliation of non-GAAP results to GAAP
results for historic periods can be found on slide 34 of this presentation and in our filings
with the SEC, as applicable. |
 Company Overview
|
 4
Founded by current Chairman and CEO Josh Comstock
Well-positioned to benefit from many of the most important trends in drilling and
completion Focused on complex, technically demanding completions that deliver superior
returns Operates modern, high-pressure rated equipment
Integrated manufacturing capabilities
Recent rapid growth through penetration of prominent E&P customers
Unique
financial
business
model
through
“take-or-pay
plus”
contracts
covering
a
majority
of
fleets that combine visibility with spot upside optionality
C&J is a Differentiated Energy Services Company |
 1997
1998
1999
2000
2001
2002
2003
2004
2005
2006
2007
2008
2009
2010
2011
5
Josh
Comstock
founded C&J
Introduced stand-
alone pressure
pumping services
Ordered first
hydraulic
fracturing fleet
Added 5 coiled tubing units, bringing total to 13
Geographic expansion into East Texas
Launched hydraulic fracturing service
Contracted Fleets 1 and 2
Ordered Fleets 3, 4 and 5
Evolution of C&J
Introduced
coiled tubing
services
C&J Timeline
Key Customers
Closed Total Acquisition
Coiled tubing count reaches 18 units
Contracted Fleets 3, 4, 5 and 6
Ordered Fleets 7, 8, 9
2012
Ordered 6 additional
coiled tubing units |
 6
C&J Investment Highlights
Operational
expertise in
service-intensive
basins
Visible revenue
growth
Modern, high-
specification
equipment
High-quality
service
Focused on technically-demanding, service-intensive basins
Generate higher revenue per unit of horsepower relative to peers
Customized solutions through extensive front-end technical analysis and
planning
Design
engineers
and
job
supervisors
involved
throughout
project
execution
Exclusive focus on high-pressure rated equipment (all rated up to 15,000 psi)
Modern
fracturing
fleet,
averaging
two
years
old
and
all
entered
into
service
in the past five years
Acquisition of Total provides specialized, in-house manufacturing capability
Substantial hydraulic fracturing and completion services experience
Vested executive team with significant ownership
Experienced
management
Scheduled equipment deliveries to support sustained growth
Term contracts provide visibility with flexibility for spot market upside
|
 Industry Trends
|
 Ongoing development of existing and emerging unconventional resource basins
-
Increased horizontal drilling
-
Greater service intensity
Favorable
North American supply-demand fundamentals
-
Increased demand for expertise to execute complex completions
-
High levels of asset utilization
Spread of North American unconventional drilling and completion techniques
-
Conventional field redevelopment applications
-
Actively pursuing coiled tubing and fracturing opportunities with multiple
potential customers in the Middle East
8
Key Industry Themes Driving C&J Opportunity
Emerging international opportunities |
 0 %
10 %
20 %
30 %
40 %
50 %
60 %
70 %
80 %
0
500
1000
1500
2000
2500
Jun-07
Aug-08
Nov-09
Jan-11
Apr-12
Oil-directed drilling rigs
Gas-directed drilling rigs
% Horizontal / Directional
+ 6 %
+ 20 %
+ 57 %
Granite Wash
Permian
Eagle Ford
Current
Rig Count
203
311
87
Source: Left-side chart from Unconventional Drilling Report as of February 23, 2012; right-side
chart from Baker Hughes Rig Count data as of April 05, 2012 Strong Drilling Outlook Drives
Completion Demand U.S. Horizontal Rig Count
Rig Count Change Since Q1 2011
9
Significant increase in rig count and horizontal drilling activity
Increased service intensity of horizontal wells |
 10
Source: Goldman Sachs Equity Research
Note: Dark blue bars denote current C&J basin of operation.
Advances in Completion Techniques Driving Demand
Average Fracturing Stages Per Well
Average Horsepower Per Well (000’s of HP)
40
38
30
25
11
Permian
Eagle
Ford
Granite
Wash
Other
Unconventional
Median
Conventional
16
16
12
13
3
Permian
Eagle
Ford
Granite
Wash
Other
Unconventional
Median
Conventional
Longer laterals
More frac stages
Higher pressure wells |
 11
Favorable Long-Term Supply / Demand Fundamentals
Demand-Side Drivers
Supply-Side Drivers
Continued increase in horizontal drilling
Longer laterals
Growing number of fracturing stages per well
Improved drilling efficiencies
High-pressure environments
Customized approach to the completion of
complex, technically demanding wells
Redevelopment of conventional fields
High oil prices largely offsetting low natural
gas prices
Older equipment not well-suited to meet
demanding completion requirements
Significant increase in attrition and
maintenance downtime
-
24-hour continuous service
-
More aggressive sand / proppant use
-
More demanding operating conditions in
higher pressure formations
Limited industry experience executing the
most complex completions |
 Business
Overview |
 13
Overview of Service Offerings
Services
Hydraulic
Fracturing
Pressure
Pumping
Coiled Tubing
Provide highly customized services for
technically challenging basins
Engineering staff offers extensive
front-end technical evaluation
Demonstrated efficiency gains to client
allows for premium pricing
Ability to handle heavy-duty jobs across
a wide spectrum of environments
Provides various functions associated
with well completion and well servicing
Leverage CT business to expand into
additional fracturing opportunities
Diverse portfolio of value-added
services
Routinely performed in conjunction with
coiled tubing services
Often provides advanced knowledge of
potential coiled tubing work
Focus on most
complex projects in
most challenging
basins |
 14
Highly Experienced Management Team
Josh Comstock
Founder,
Chairman and CEO
Randy McMullen
EVP,
CFO and Treasurer
Brett Barrier
COO
John Foret
VP, Coiled Tubing
Billy Driver
VP, Hydraulic
Fracturing
Brandon
Simmons
VP, Coiled Tubing
Pat Winstead
VP, Marketing
Ted Moore
VP, General Counsel
Industry
Experience
20+ years
Industry
Experience
20+ years
Industry
Experience
10+ years
Industry
Experience
20+ years
Industry
Experience
25+ years
Industry
Experience
18+ years
Industry
Experience
25+ years
Industry
Experience
9+ years |
 15
Modern, High-Specification Equipment
Currently operates seven modern 15,000 psi pressure rated hydraulic fracturing
fleets with aggregate of 242,000 horsepower
–
Specifically designed to handle well completions with long lateral segments and
multiple fracturing stages in high pressure formations
Also owns a fleet of 18 coiled tubing units, 21 double-pump pressure pumps
and 9 single-pump pressure pumps
–
Additional 6 coiled tubing units and ancillary equipment to be delivered in
the second half of 2012 for
deployment to new geographic basins –
22 of the 24 coiled tubing units will be 2-inch dimension
Vertical integration through acquisition of Total E&S
(“Total”) Premium Hydraulic Fracturing Fleets
Current Fleets
Year Built
On-Time Delivery
Number of Pressure Pumps
Horsepower Capacity
1
2007
17
34,000
2
2010
12
24,000
3
2010
16
32,000
4
2011
20
40,000
5
2011
16
32,000
6
2011 / 2012
24
48,000
7
2Q 2012
16
32,000
Expected Fleets
Expected Delivery Date
On-Time Delivery
Number of Pressure Pumps
Horsepower Capacity
8
3Q 2012
16
32,000
9
4Q 2012
16
32,000
Total
153
306,000 |
 16
Geographically Focused in Attractive Basins
= C&J Customer Relationship
Granite Wash
Eagle Ford Shale
Haynesville Shale
= Basin where C&J is currently active
Existing relationships provide platform for future growth
Prominent shales are in reach of C&J’s existing service centers
Company
Coiled
Tubing
Hydraulic
Fracturing
Chesapeake
Encana
Samson
Petrohawk
EOG
Shell
Devon
Plains Exploration
EXCO
Penn Virginia
Company
Coiled
Tubing
Hydraulic
Fracturing
Chesapeake
Apache
Forest Oil
Cordillera
Newfield
Unit
Penn Virginia
Company
Coiled
Tubing
Hydraulic
Fracturing
Chesapeake
EOG
Petrohawk
Newfield
Anadarko
Shell
SM Energy
ConocoPhillips |
 Offer customized
solutions on a job-by-job basis
Engineers and fleet managers
onsite throughout process
Culture of flexibility and
collaboration
Completed thousands of
fracturing stages in Eagle
Ford and Haynesville
Operating team with 20+
years of in-basin experience
Relationships with several
proppant and chemical
suppliers
Technical proficiency and
front-end analysis
The Result is Enhanced Economics for Our Customers
Superior
customer
service
New, highly
capable
equipment
Exceptional
execution
High-quality
service
provider
Minimize cycle time and limit
pump downtime
Design fluids that perform well
in various environments
Focus on maintaining
performance data that is used
to supplement and increase
effectiveness of future
assignments
We Offer an Attractive Value Proposition to Our Customers
All fracturing fleets less than 5
years old; rated for 15,000 psi
Optimized configuration of fleet
according to basin specific
requirements
Custom-designed equipment
maximizes efficiency and
durability
Specific competence in
fracturing fluid design and local
application
17 |
 18
Relationships with Industry Leaders
(Through mid-2012)
(Through mid-2012)
(Through early 2013)
(Through mid-2014)*
(Through mid-2013)
Large operators have embraced C&J’s technical capabilities
(Early 2014)
*Under contract but currently deployed to Eagle Ford to different customers.
EXCO retains contractual ability to call fleet back to Haynesville with proper
notice.
Current Service Offerings
Customer
Stand Alone
Pressure Pumping
Coiled Tubing
Hydraulic
Fracturing
Term Frac Contract |
 19
Outperformance Through Efficiency
Pre-job best
practices
Pumping
procedures
Motivated
workforce
Rig-up
flexibility
More frequent communication with customers during well design process
Lab fluids testing in advance for optimal well design
Develop best layout for job site to maximize Hydration Unit and Blender
performance Organize crew into focused teams to complete multiple tasks
simultaneously Conduct field fluid tests during rig-up process to
confirm lab results Real-time monitoring of equipment to spot potential
problems early On-site maintenance of pump units as soon as each one is
offline Proactive replacement of wear items rather than waiting for a
failure Streamline paperwork requirements to allow supervisors to focus on
efficiency and planning
Empowering employees and promoting best practices produces a proud and highly
motivated workforce
Engineers
and
blender
operators
on
site
during
rig
up
to
“jump
start”
technical
review
Continuity
of
technical
staff
to
avoid
repetition
and
save
customers’
time |
 20
Strategy for Continued Growth
Capitalize on growth in development of shale and other resource plays
Leverage customer relationships to geographically expand
–
Further expansion into new geographic basins
–
Evaluating opportunities to expand operations into new areas throughout the
U.S. Pursue additional term hydraulic fracturing contracts
–
Currently seeking term contracts for Fleets 7, 8 and 9
Maintain flexibility to pursue spot market work |
 Financials
|
 22
Key Drivers of Financial Performance
Business Model
Financial Model
Visibility
Growth
Vertical integration
Risk management
Hourly rates under take-or-pay contracts
Spot market optionality
Utilization drives model
Balance sheet strength |
 23
Significant Historical Growth
Growth in HHP (period end)
Avg. Monthly Revenue / HHP
Adjusted EBITDA ($mm)
Revenue ($mm)
$285.0
1
Assumes timely delivery of Fleets 8 & 9
$758.5 |
 24
More demanding wells drive higher hourly rates and higher revenues from
chemicals and proppant
More frac stages per well keep fleets onsite longer, allowing more pumping hours
per month
Demonstrated
shorter
time
per
completion
permits
us
to
negotiate
premium
rates
with customers
Less redundant pumping capacity boosts utilization
Average monthly revenue per unit of horsepower:
-
$336 in 2010
-
$374 in 2011
ROCE of 42% in 2010 and 57% in 2011
Operational Strategy Drives Strong Financial Performance
Regional focus and operating efficiency generate higher revenues per unit of horsepower |
 25
Strong Margin Profile
EBITDA Margin¹
1
EBITDA margin based on Adjusted EBITDA.
Margins driven by utilization, not price
In 2011 generated $285MM in Adjusted EBITDA
31%
19%
34%
38%
2008
2009
2010
2011 |
 26
Contract Coverage for Fracturing Fleets
2011
2012
Operating Regions
Q1
Q2
Q3
Q4
Q1
Q2
Q3
Q4
Fleet 1
Eagle Ford
Fleet 2
Eagle Ford
Fleet 3
Eagle Ford
Fleet 4*
Eagle Ford
Fleet 5
Eagle Ford
Fleet 6
Permian
Fleet 7
Permian
(Spot Market)
Fleet 8
(Uncontracted)
Fleet 9
(Uncontracted)
Fleet Under Contracts
Expected Delivery of Future Fleets
Delivered and Scheduled to be
Deployed in Spot Market in April 2012
Scheduled for Delivery in
3Q 2012
Fracturing Term Contracts Provide Visible Growth
Scheduled for
Delivery 4Q 2012
* Under contract but currently
deployed to Eagle Ford to different customers. EXCO retains contractual ability
to call fleet back to Haynesville with proper notice.
Fleet Operating in Spot Market |
 27
Overview of Term Contracts Covering Fleets 1-6
•
1 –
3 year contract life
•
Revenues under term contracts are derived from:
–
Mandatory monthly payments for minimum hours*
–
Pre-agreed amounts for each hour of service in excess of the contracted
minimum
–
Service charge to customers for chemicals and proppant materials
•
Take or pay
•
Optionality to deploy equipment when not utilized
•
Contractual protections for term
*When
Fleet
4
is
working
for
non-contractual
customers
outside
of
the
Haynesville
then
C&J
is
not
collecting
from
the
Haynesville
contractual customer. |
 28
Total E&S Acquisition Facilitates Growth Strategy
Total E&S is a manufacturer of hydraulic fracturing equipment, coiled tubing,
pressure
pumping
and
other
equipment
used
in
the
energy
services
industry
and one of C&J’s largest suppliers of machinery and equipment
–
Acquisition closed April 28, 2011
–
Aggregate purchase price of approximately $33.0mm
–
Received
$5.4mm
cash
as
part
of
acquisition,
for
net
transaction
value
of
$27.5mm
–
$25.0mm financed through incremental revolver borrowings
–
Remainder funded through cash on hand
Strategic benefits include
–
Internal control over supply chain
–
Significantly reduces exposure to third-party supply constraints
–
Shorter cycle times for the delivery of new equipment and replacement parts
–
Provides for greater potential control of costs associated with new equipment
–
Acquisition has reduced C&J’s procurement costs from Total
–
Ability to delay, or indefinitely postpone, delivery time of equipment
–
Platform for R & D, continued equipment design improvements |
 Strong Balance Sheet and Liquidity
Flexible balance sheet with strong liquidity position
–
$200mm revolving credit facility
29
.
Improved Balance Sheet
($ in thousands)
6/30/2011
12/31/2011
Cash and Cash Equivalents
$
7,634
$
46,780
Long-term Debt
Five-Year $200mm Credit Facility
$
105,000
-
Total Long-Term Debt
$
105,000
-
Shareholders' Equity
$
176,039
$
395,055
Total Capitalization
$
281,039
$
395,055 |
 Appendix
|
 Detailed
Historical
Financials
–
Income
Statement
31
Year Ended December 31,
($ in thousands except per share amounts)
2007
2008
2009
2010
2011
Statement of Operations Data
Revenue
$28,022
$62,441
$67,030
$244,157
$758,454
Cost of Sales
14,227
42,401
54,242
154,297
443,556
Gross Profit
$13,795
$20,040
$12,788
$89,860
$314,898
Selling, General and Administrative Expenses
7,427
8,950
9,533
17,998
52,737
Loss (Gain) on Sale / Disposal of Assets
129
397
920
1,571
(25)
Operating Income
$6,239
$10,693
$2,335
$70,291
$262,186
Other Income (Expense)
Interest Income
$50
$5
$4
$9
–
Interest Expense
(5,786)
(6,913)
(4,712)
(17,350)
$(4,221)
Lender Fees
(341)
(511)
(391)
(322)
–
Loss on early extinguishment of debt
–
–
–
–
(7,605)
Other Income
–
–
–
163
–
Other Expense
(17)
(68)
(52)
(150)
(40)
Total Other Expenses
$(6,094)
$(7,487)
$(5,151)
$(17,650)
$(11,866)
Income (Loss) Before Income Taxes
$145
$3,206
$(2,816)
$52,641
$250,320
Provision (Benefit) for Income Taxes
868
2,085
(386)
20,369
88,341
Net Income (Loss)
$(723)
$1,121
$(2,430)
$32,272
$161,979
Basic Net Income (Loss) per Share
$(0.02)
$0.02
$(0.05)
$0.70
$3.28
Diluted Net Income (Loss) per Share
(0.02)
0.02
(0.05)
0.67
3.19
(Unaudited) |
 Detailed
Historical
Financials
–
Cash
Flow
32
Year Ended December 31,
( $ in thousands)
2007
2008
2009
2010
2011
Statement of Cash Flows Data
Capital Expenditures
$30,152
$21,526
$4,301
$44,473
$140,723
Cash Flow Provided by (Used in)
Operating Activities
$8,377
$8,611
$12,056
$44,723
$171,702
Investing Activities
(30,054)
(20,673)
(4,254)
(43,818)
(165,545)
Financing Activities
21,305
11,921
(6,733)
734
37,806
(Unaudited) |
 Detailed
Historical
Financials
–
Balance
Sheet
33
As of December 31,
($ in thousands)
2007
2008
2009
2010
2011
Balance Sheet Data
Cash and Cash Equivalents
$250
$109
$1,178
$2,817
$46,780
Accounts Receivable, Net
4,409
13,362
12,668
44,354
122,169
Inventories, Net
581
861
2,463
8,182
45,440
Property, Plant and Equipment, Net
57,991
71,441
65,404
88,395
213,697
Total Assets
133,711
155,212
150,231
226,088
537,849
Accounts Payable
1,705
6,519
10,598
14,524
57,564
Long-term Debt and Capital Lease Obligations,
Excluding Current Portion
56,773
25,041
60,668
44,817
Total Stockholders' Equity
$66,797
$68,099
$65,799
$109,446
$395,055
(Unaudited)
- |
 EBITDA
Reconciliation 34
Year Ended December 31,
($ in thousands)
2008
2009
2010
2011
Net Income (Loss)
$1,121
$(2,430)
$32,272
$161,979
Interest Expense, Net
6,909
4,708
17,341
4,221
Provision (Benefit) for Income Taxes
2,085
(386)
20,369
88,341
Depreciation and Amortization
8,836
9,828
10,744
22,919
EBITDA
$18,951
$11,720
$80,726
$277,460
Adjustments to EBITDA
Loss on early extinguishment of debt
7,605
Loss (Gain) on Sale / Disposition of Property,
Plant & Equipment
397
920
1,571
(25)
Adjusted EBITDA
$19,348
$12,640
$82,297
$285,040
Note: EBITDA and Adjusted EBITDA are
non-GAAP financial measures, and when analyzing C&J’s operating performance, investors should use EBITDA and Adjusted
EBITDA in addition to, and not as an alternative for, operating income and net income (loss)(each as
determined in accordance with GAAP). C&J uses EBITDA and Adjusted EBITDA as
supplemental financial measures. EBITDA is defined as net income (loss) before interest expense (net), income taxes, depreciation and amortization.
Adjusted EBITDA is EBITDA further adjusted for certain other items which are not indicative of future
performance or cash flow, including loss on early extinguishment of debt and loss (gain) on
sale/disposal of property, plant and equipment. C&J believes EBITDA and Adjusted EBITDA are useful supplemental indicators of its performance.
EBITDA and Adjusted EBITDA, as used and defined by C&J, may not be comparable to similarly titled
measures employed by other companies and are not measures of performance calculated in
accordance with GAAP.
|