 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. |