Attached files
| file | filename |
|---|---|
| 8-K - FORM 8-K - C&J Energy Services, Inc. | d310164d8k.htm |
 C&J Energy
Services, Inc. Investor Presentation
March 1, 2012
Exhibit 99.1 |
 2
Disclaimer
Forward-Looking Statements
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 period 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.
Non-GAAP Financial Measures
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 35 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
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
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
C&J Timeline
Key Customers |
 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
Exclusive focus on high-pressure rated equipment (all rated up to 15,000 psi)
Modern fracturing fleet, all entered into service in the past four 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
Customized solutions through extensive front-end technical analysis and planning Design engineers and job supervisors involved throughout project execution |
 Industry Trends
|
 Ongoing development
of existing and emerging unconventional resource basins Increased horizontal drilling
Greater service intensity
Strong North American supply-demand fundamentals
Increased demand for expertise to execute complex completions
High levels of asset utilization and constrained supply growth
Spread of North American unconventional drilling and completion techniques
Conventional field redevelopment applications
Emerging international opportunities
8
Key Industry Themes Driving C&J Opportunity |
 Source: Unconventional
Drilling data as of September 2011 and Baker Hughes Rig Count data as of November 04, 2011.
Strong Drilling Outlook Drives Completion Demand
% Horizontal / Directional
9
Significant increase in rig count and horizontal drilling activity
Increased service intensity of horizontal wells
Rig Count Change Since 6/09 by Shale Play
U.S. Horizontal Rig Count |
 10
Source: Goldman Sachs Equity Research, management estimates.
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
Haynesville
Eagle
Ford
Granite
Wash
Other
Unconventional
Median
Conventional
16
16
12
13
3
Haynesville
Eagle
Ford
Granite
Wash
Other
Unconventional
Median
Conventional
Longer laterals
More frac stages
Higher pressure wells |
 11
Favorable Supply / Demand Fundamentals
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
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
Supply chain constraints in obtaining new
equipment
Limited industry experience executing the
most complex completions
Demand-Side Drivers
Supply-Side Drivers |
 Business
Overview |
 13
Overview of Service Offerings
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
Leverage CT business to expand into
additional fracturing opportunities
Provides various functions associated
with well completion and well servicing
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
Services |
 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 six modern 15,000 psi pressure rated hydraulic fracturing fleets with
aggregate of 210,000 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 –
20 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
Expected Fleets
Expected Delivery Date
On-Time Delivery
Number of Pressure Pumps
Horsepower Capacity
7
2Q 2012
16
32,000
8
3Q 2012
16
32,000
9
4Q 2012
16
32,000
Total
153
306,000 |
 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
16
Geographically Focused in Attractive Basins
=
C&J
Customer
Relationship
Granite Wash
Company
Coiled
Tubing
Hydraulic
Fracturing
Chesapeake
EOG
Petrohawk
Newfield
Anadarko
Shell
SM Energy
ConocoPhillips
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 |
 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 4
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)
(Early 2014)
Large operators have embraced C&J’s technical capabilities
Term Frac Contract
Hydraulic
Fracturing
Coiled Tubing
Stand Alone
Pressure Pumping
Customer
Current Service Offerings |
 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 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
Continuity of technical staff to avoid repetition and save customers’ time
Engineers and blender operators on site during rig up to “jump start” technical review |
 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
–
Retains upside revenue potential at prevailing market rates |
 Financials
|
 22
Key Drivers of Financial Performance
Visibility
Growth
Vertical integration
Risk management
Hourly rates under take-or-pay contracts
Spot market optionality
Utilization drives model
Balance sheet strength
Business Model
Financial Model |
 23
Significant Historical Growth
34,000
58,000
130,000
178,000
300,000
2009
2010
Apr-11
2011
2012E¹
$19.9
$13.1
$82.3
2008
2009
2010
2011
$62.4
$67.0
$244.2
2008
2009
2010
2011
$67
$93
$331
$374
2008
2009
2010
2011
$285.0
$758.5
Revenue ($mm)
Adjusted EBITDA ($mm)
Growth in HHP (period end)
Avg. Monthly Revenue / HHP
1
Assumes timely delivery of Fleets 6 – 9
|
 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:
$331 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
31%
19%
34%
38%
2008
2009
2010
2011
1
EBITDA margin based on Adjusted EBITDA.
Margins driven by utilization, not price
In 2011 generated $285MM in Adjusted EBITDA
EBITDA Margin¹ |
 26
Contract Coverage for Fracturing Fleets
Delivery 2Q 2012
Delivery 2Q 2012
Fracturing Term Contracts Provide Visible Growth
Delivery 4Q 2012
Fleet 1
Fleet 2
Fleet 9
Fleet 6
Fleet 7
Fleet 8
Fleet 5
Fleet 4
Fleet 3
Operating Regions
Haynesville/Eagle
Ford/Granite wash
Eagle Ford
Eagle Ford
Eagle Ford
Eagle Ford
Permian
(Uncontracted)
(Uncontracted)
(Uncontracted)
2011
2012
Q1
Q2
Q3
Q4
Q1
Q2
Q3
Q4
Expected Delivery of Future Fleets
Fleet Under Contracts |
 27
Overview of Term Contracts
•
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 |
 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 |
 30
C&J Investment Highlights
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
Exclusive focus on high-pressure rated equipment (all rated up to 15,000 psi)
Modern fracturing fleet, all entered into service in the past four 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
Operational
expertise in
service-intensive
basins
Customized solutions through extensive front-end technical analysis and
planning
Design engineers and job supervisors involved throughout project execution |
 Appendix
|
 Detailed
Historical
Financials
–
Income
Statement
32
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
33
Year Ended December 31,
( $ in thousands except per share amounts)
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
34
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
13,084
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
$395,055
(Unaudited) |
 EBITDA
Reconciliation 35
Year Ended December 31,
($ 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: EBIT, EBITDA and Adjusted EBITDA are
non-GAAP financial measures, and when analyzing C&J’s operating performance, investors should use EBIT, EBITDA
and Adjusted EBITDA in addition to, and not as an alternative for, operating income and
net (loss) income (each as determined in accordance with GAAP). C&J uses EBIT,
EBITDA and Adjusted EBITDA as supplemental financial measures. EBIT is defined as net income (loss) before interest expense (net) and income taxes.
EBITDA is EBIT adjusted for depreciation and amortization. Adjusted EBITDA is EBITDA further
adjusted for certain other items which are not indicative of future performance or cash flow,
including lender fees, other non-operating expenses and loss on sale/disposal of property, plant and equipment. C&J believes EBIT, EBIDA
and Adjusted EBITDA are useful supplemental indicators of its performance. EBIT, 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. |