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EX-23.2 - CONSENT OF GRANT THORNTON LLP - CHESAPEAKE OILFIELD SERVICES INCd330734dex232.htm
EX-23.1 - CONSENT OF PRICEWATERHOUSECOOPERS LLP - CHESAPEAKE OILFIELD SERVICES INCd330734dex231.htm
Table of Contents
Index to Financial Statements

As filed with the Securities and Exchange Commission on April 16, 2012

Registration No. 333-            

 

 

 

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

 

 

Form S-1

REGISTRATION STATEMENT

UNDER

THE SECURITIES ACT OF 1933

 

 

Chesapeake Oilfield Services, Inc.

(Exact name of registrant as specified in its charter)

 

 

 

Oklahoma   1389   45-5011340

(State or other jurisdiction of

incorporation or organization)

 

(Primary Standard Industrial

Classification Code Number)

 

(I.R.S. Employer

Identification No.)

6100 North Western Avenue

Oklahoma City, Oklahoma 73118

(405) 848-8000

(Address, including zip code, and telephone number, including area code, of registrant’s principal executive offices)

 

 

Jerry L. Winchester

Chief Executive Officer

6100 North Western Avenue

Oklahoma City, Oklahoma 73118

(405) 848-8000

(Name, address, including zip code, and telephone number, including area code, of agent for service)

 

 

Copies to:

 

Michael S. Telle

Bracewell & Giuliani LLP

711 Louisiana Street, Suite 2300

Houston, Texas 77002

(713) 221-1327

 

William S. Moss III

Mayer Brown LLP

700 Louisiana Street, Suite 3400

Houston, Texas 77002

(713) 238-2649

 

 

Approximate date of commencement of proposed sale to the public: As soon as practicable after the effective date of this registration statement.

If any of the securities being registered on this Form are to be offered on a delayed or continuous basis pursuant to Rule 415 under the Securities Act of 1933 check the following box:    ¨

If this Form is filed to register additional securities for an offering pursuant to Rule 462(b) under the Securities Act, please check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering.    ¨

If this Form is a post-effective amendment filed pursuant to Rule 462(c) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering.    ¨

If this Form is a post-effective amendment filed pursuant to Rule 462(d) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering.    ¨

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):

 

Large accelerated filer   ¨    Accelerated filer   ¨
Non-accelerated filer   þ  (Do not  check if a smaller reporting company)    Smaller reporting company   ¨

 

 

CALCULATION OF REGISTRATION FEE

 

 

Title of Each Class of

Securities to Be Registered

  Proposed
Maximum
Aggregate
Offering
Price(1)(2)
  Amount of
Registration Fee

Class A Common Stock, par value $0.001 per share

  $862,500,000   $98,843

 

 

(1) Estimated solely for the purpose of calculating the registration fee pursuant to Rule 457(o) under the Securities Act of 1933, as amended.
(2) Includes approximately $112,500,000 attributable to shares of Class A common stock that may be offered upon exercise of a 30-day option to purchase additional shares granted to the underwriters.

 

 

The registrant hereby amends this registration statement on such date or dates as may be necessary to delay its effective date until the registrant shall file a further amendment which specifically states that this registration statement shall thereafter become effective in accordance with Section 8(a) of the Securities Act of 1933 or until the registration statement shall become effective on such date as the Commission acting pursuant to said Section 8(a), may determine.

 

 

 


Table of Contents
Index to Financial Statements

The information in this preliminary prospectus is not complete and may be changed. These securities may not be sold until the registration statement filed with the Securities and Exchange Commission is effective. This preliminary prospectus is not an offer to sell nor does it seek an offer to buy these securities in any jurisdiction where the offer or sale is not permitted.

 

Subject to Completion

Preliminary Prospectus dated April 16, 2012

                         Shares

 

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Chesapeake Oilfield Services, Inc.

Class A Common Stock

 

 

This is an initial public offering of the Class A common stock of Chesapeake Oilfield Services, Inc. We are offering                 shares of our Class A common stock.

Prior to this offering, there has been no public market for our Class A common stock. We anticipate that the initial public offering price of our Class A common stock will be between $         and $         per share. We intend to apply to list our Class A common stock on the New York Stock Exchange under the symbol “COS.”

Concurrently with the consummation of this offering, we will issue                 shares of our Class B common stock, each share of which initially entitles the holder to                 votes per share, to Chesapeake Energy Corporation. Through its ownership of our Class B common stock, Chesapeake will hold     % of the combined voting power of our outstanding common stock immediately after this offering.

 

 

See “Risk Factors” on page 25 to read about factors you should consider before buying shares of our Class A common stock.

 

 

Neither the Securities and Exchange Commission nor any state securities commission has approved or disapproved of these securities or passed upon the accuracy or adequacy of this prospectus. Any representation to the contrary is a criminal offense.

 

 

 

     Per Share      Total  

Initial public offering price

   $                    $                

Underwriting discount

   $                    $                

Proceeds, before expenses, to Chesapeake Oilfield Services, Inc.

   $                    $                

The underwriters have the option, exercisable for 30 days from the date of this prospectus, to purchase up to                  additional shares of our Class A common stock at the initial public offering price less the underwriting discount.

 

 

The underwriters expect to deliver the shares against payment in New York, New York on                     , 2012.

 

Goldman, Sachs & Co.   BofA Merrill Lynch

 

 

Prospectus dated                     , 2012.


Table of Contents
Index to Financial Statements

TABLE OF CONTENTS

 

 

     Page  

PROSPECTUS SUMMARY

     1   

RISK FACTORS

     25   

CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS

     47   

ORGANIZATIONAL STRUCTURE

     48   

USE OF PROCEEDS

     51   

CAPITALIZATION

     53   

DILUTION

     54   

SELECTED HISTORICAL AND AS ADJUSTED FINANCIAL DATA

     55   

MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

     57   

BUSINESS

     79   

MANAGEMENT

     102   

CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS

     106   

PRINCIPAL SHAREHOLDER

     114   

DESCRIPTION OF CAPITAL STOCK

     116   

SHARES ELIGIBLE FOR FUTURE SALE

     121   

DESCRIPTION OF CERTAIN INDEBTEDNESS

     123   

EXECUTIVE COMPENSATION AND OTHER INFORMATION

     125   

MATERIAL U.S. FEDERAL INCOME TAX CONSIDERATIONS TO NON-U.S. HOLDERS

     134   

UNDERWRITING

     138   

LEGAL MATTERS

     144   

EXPERTS

     144   

WHERE YOU CAN FIND MORE INFORMATION

     145   

INDEX TO FINANCIAL STATEMENTS

     F-1   

 

 

Through and including                     , 2012 (the 25th day after the date of this prospectus), all dealers effecting transactions in these securities, whether or not participating in this offering, may be required to deliver a prospectus. This is in addition to a dealer’s obligation to deliver a prospectus when acting as an underwriter and with respect to an unsold allotment or subscription.

 

 

We have not authorized anyone to provide any information or to make any representations other than those contained in this prospectus or in any free writing prospectuses we have prepared. We take no responsibility for, and can provide no assurance as to the reliability of, any other information that others may give you. This prospectus is an offer to sell only the shares offered hereby, but only under circumstances and in jurisdictions where it is lawful to do so. The information contained in this prospectus is current only as of its date.

Industry and Market Data

The market data and certain other statistical information used throughout this prospectus, including statements as to our ranking, market position and market estimates, are based on independent industry publications, government publications or other published independent sources. Some data is also based on our good faith estimates. Prospective investors are cautioned not to place undue reliance on such data and information due to the fact that it may be based on our estimates or, if derived from a third party, we have not verified it.

 

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Index to Financial Statements

PROSPECTUS SUMMARY

This summary provides a brief overview of information contained elsewhere in this prospectus. This summary does not contain all of the information that you should consider before investing in our Class A common stock. You should read the entire prospectus carefully before making an investment decision, including the information presented under the headings “Risk Factors,” “Cautionary Note Regarding Forward-Looking Statements,” “Organizational Structure” and “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and the historical consolidated financial statements and related notes thereto included elsewhere in this prospectus.

On October 25, 2011, Chesapeake completed the process of reorganizing its oilfield services subsidiaries and operations as subsidiaries of COS Holdings, L.L.C. (“COS LLC”) and commenced providing all of its oilfield services through COS LLC, as more fully described under “Organizational Structure.” As a result, the historical financial information presented in this prospectus for periods and as of dates prior to that October 25, 2011 reorganization is the historical consolidated financial information of our “predecessor” or “Chesapeake Oilfield Services Predecessor.” The historical financial information presented in this prospectus for periods and as of dates on or after that October 25, 2011 reorganization is the historical consolidated financial information of COS LLC.

In this prospectus, unless the context otherwise requires, the terms “we,” “us,” “our” or “ours” refer to COS LLC and its subsidiaries and predecessor entities prior to this offering and to Chesapeake Oilfield Services, Inc. (“COS Inc.”) and its subsidiaries, including COS LLC, from and after this offering. See “—Organizational Structure.” References to “Chesapeake Oilfield Operating” or “COO” mean Chesapeake Oilfield Operating, L.L.C., a wholly owned subsidiary of COS LLC, which is the borrower under our revolving bank credit facility and the co-issuer of our 6.625% Senior Notes due 2019 (the “2019 Senior Notes”). References to “Chesapeake” mean Chesapeake Energy Corporation and its subsidiaries (excluding us), unless the context indicates otherwise.

Our Company

We are a diversified oilfield services company that provides a wide range of well site services primarily to Chesapeake, our founder and principal customer, and its partners. Chesapeake is the most active driller of new oil and natural gas wells in the U.S. based on rig count. We focus on providing services to Chesapeake that are strategic to its oil and gas operations, represent historical bottlenecks to those operations or provide relatively high margins to the service provider, including drilling, hydraulic fracturing, oilfield rentals, oilfield trucking and manufacturing of natural gas compressor packages. Our operations are geographically diversified across most major basins in the U.S. Specifically, we provide Chesapeake and its partners with services in the Eagle Ford, Utica, Granite Wash, Cleveland, Tonkawa, Mississippi Lime, Bone Spring, Avalon, Wolfcamp, Wolfberry and Niobrara unconventional liquids plays and the Barnett, Haynesville, Bossier, Marcellus and Pearsall natural gas shale plays.

Our objective is to provide up to two-thirds of Chesapeake’s overall expected needs for our current and future services. This objective, combined with our unique relationship with Chesapeake, makes us fundamentally different than our competitors because it provides us with substantial growth opportunities while at the same time positioning us to maintain our industry-leading asset utilization rates. We believe that our high-growth, high-utilization business model will allow us to continue creating significant shareholder value over time.

 

 

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Our business has grown rapidly since our first subsidiary was founded in 2001, both organically and through acquisitions, and we are now one of the larger U.S. onshore oilfield service companies. We currently operate 111 land drilling rigs, the fourth largest active rig fleet in the U.S., which represents our largest revenue generating service line today. We also operate (a) four hydraulic fracturing fleets with an aggregate of 140,000 horsepower; (b) one of the largest oilfield rental businesses in the U.S.; (c) one of the largest oilfield trucking fleets in the U.S., currently consisting of 227 rig relocation trucks, 57 cranes and forklifts used in the movement of drilling rigs and other heavy equipment and 157 fluid hauling trucks; and (d) manufacturing capacity for up to 150 compressor units per quarter, or approximately 85,000 horsepower in the aggregate per quarter. We continue to grow our assets rapidly and have ordered 12 drilling rigs that will utilize advanced electronic drilling technology, including 10 of our proprietary, fit-for-purpose PeakeRigs, which are scheduled to be delivered at a rate of approximately one rig per month through May 2013. We have also ordered additional new hydraulic fracturing equipment with an aggregate of 175,000 horsepower, and we expect to have eight hydraulic fracturing fleets with an aggregate of 315,000 horsepower operating by the end of 2012 and 12 such fleets with an aggregate of 450,000 horsepower operating by the end of 2013. We believe our growth plans will place us among the largest hydraulic fracturing companies in the U.S. by year-end 2014 based on horsepower.

The services that we provide to Chesapeake are fundamental to establishing and maintaining the production of oil and natural gas from its wells. As of December 31, 2011, Chesapeake had total estimated net proved reserves of approximately 18.8 trillion cubic feet of natural gas equivalent (tcfe), which includes approximately 545 million barrels (mmbbls) of oil and natural gas liquids, which we refer to collectively as “liquids,” and was operating 162 drilling rigs to develop its inventory of approximately 39,000 risked net drill sites. During 2011, Chesapeake utilized hydraulic fracturing fleets with an average of approximately 1.0 million horsepower per day. For 2012 and 2013, Chesapeake’s gross operated drilling and completion capital expenditure budgets are approximately $11.0 billion and $12.0 billion, respectively.

Chesapeake’s operated drilling program includes expenditures by both Chesapeake and its partners. The charts below show the percentage of budgeted capital expenditures expected to be funded by Chesapeake and its partners in 2012 and 2013.

Chesapeake’s Gross Operated Drilling and Completion

Capital Expenditure Budget

 

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We currently supply Chesapeake with small percentages of its overall requirements for most of our services, which presents us with significant organic growth opportunities. For example, during the year ended December 31, 2011, our revenues from hydraulic fracturing represented less than 1% of Chesapeake’s gross operated expenditures for hydraulic fracturing services and our revenues from oilfield equipment rentals would have represented approximately 19% of its gross operated expenditures for oilfield equipment rentals. Additionally, although we already supply approximately two-thirds of Chesapeake’s current drilling rig needs, we provide low percentages of the drilling-related services it uses, such as directional drilling, mud logging and geosteering services, providing us with significant organic growth opportunities for those services as well. Likewise, while our trucking segment provides Chesapeake with a significant percentage of its rig relocation services, we provide only a small percentage of its fluid hauling requirements.

By seeking to match our productive capacity to meet up to two-thirds of Chesapeake’s expected need for our services, we anticipate that we will continue to have industry-leading asset utilization levels through industry cycles, as we believe that Chesapeake will have a number of incentives to use our services given our relationship and the operational efficiencies we provide. Moreover, Chesapeake’s drilling activity levels over time have been more stable than those of its peers. For example, in the twelve-month period ended September 30, 2009, one of the most challenging periods in the recent history of our industry, the U.S. onshore industry rig count decreased by 1,308 rigs, or 50%, while Chesapeake’s operated rig count, which includes third-party rigs, decreased by only 53 rigs, or 34%. During that same period, Chesapeake’s utilization of our rigs increased by six rigs, from 71 to 77, or 8%. Our rig utilization rates for 2009, 2010 and 2011 were 95%, 97% and 98%, respectively, compared to industry averages for the same periods of 79%, 89% and 88%, respectively. The utilization rates of our other assets are correlated with our rig utilization rates because the well drilling performed by our rigs creates demand for most of the other services we provide.

Significantly, we also have contractual arrangements with Chesapeake that provide additional revenue stability in the event of an industry downturn. Under our services agreement with Chesapeake, Chesapeake has guaranteed the utilization of the lesser of 75 of our drilling rigs or 80% of our operational drilling rig fleet at market-based rates. In addition, Chesapeake has guaranteed that each month it will ensure utilization of our operational hydraulic fracturing fleets, up to a maximum of 13 fleets, to complete a minimum aggregate number of fracturing stages equal to 25 stages per month for each fleet at market-based rates.

We currently conduct our business through five operating segments:

Drilling.    Nomac Drilling, L.L.C., our drilling subsidiary, provides premium land drilling and drilling-related services, including directional drilling, geosteering and mudlogging, for oil and natural gas exploration and development activities. As of March 31, 2012, we operated a fleet of 111 land drilling rigs, making us the fourth largest land driller operating in the U.S. according to RigData, an independent source of drilling activity information. To address Chesapeake’s needs for horizontal drilling in shale formations and other unconventional resource plays, we have expanded our areas of operation and improved the capability of our drilling rig fleet. We are in the process of building 12 new rigs that will utilize advanced electronic drilling technology, including 10 of our proprietary, fit-for-purpose PeakeRigs, which are scheduled to be delivered at a rate of approximately one rig per month through May 2013. We are also in the process of refurbishing three rigs in order to modernize and increase the capability of those rigs. For the year ended December 31, 2011, Chesapeake’s gross operated expenditures for drilling and drilling-related services were approximately $1.7 billion, and our revenues from this segment represented approximately 50% of such expenditures.

 

 

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Hydraulic Fracturing.    Performance Technologies, L.L.C., our hydraulic fracturing subsidiary, provides hydraulic fracturing and other well stimulation services. We began hydraulic fracturing operations in the fourth quarter of 2011 with one hydraulic fracturing fleet and currently have four operational fleets with an aggregate of approximately 140,000 horsepower. We plan to have eight such fleets with approximately 315,000 horsepower in the aggregate operating by the end of 2012 and 12 such fleets with approximately 450,000 horsepower in the aggregate operating by the end of 2013. For the year ended December 31, 2011, Chesapeake’s gross operated expenditures for hydraulic fracturing services were approximately $3.5 billion, and our revenues from this segment represented less than 1% of such expenditures.

Oilfield Rentals.    Great Plains Oilfield Rental, L.L.C., our oilfield rentals subsidiary, provides a wide range of premium rental tools and services for land-based oil and natural gas drilling, completion and workover activities. We offer a full line of rental tools, including drill pipe, drill collars, tubing, blowout preventers, frac and mud tanks and also provide air drilling services and services associated with the transfer of fresh water to the well site. As our oilfield rentals segment generates our highest margins and we currently supply Chesapeake with a low percentage of its overall oilfield rentals requirements, this segment offers attractive expansion opportunities, including the purchase and subsequent rental of equipment used in pressure control, flowback and hydraulic fracturing services. For the year ended December 31, 2011, Chesapeake’s gross operated expenditures for oilfield rentals were approximately $1.3 billion, and our revenues from this segment represented approximately 19% of such expenditures.

Oilfield Trucking.    Hodges Trucking Company, L.L.C. and Oilfield Trucking Solutions, L.L.C., our oilfield trucking subsidiaries, provide rig relocation and logistics services and fluid hauling services. Our trucks move drilling rigs, crude oil, fluids and construction materials to and from the well site and also transport produced water from the well site. As of March 31, 2012, we owned a fleet of 227 rig relocation trucks, 57 cranes and forklifts used in the movement of drilling rigs and other heavy equipment and 157 fluid hauling trucks. Expansion opportunities for our oilfield trucking segment include expanding our assets, such as our crude hauling capabilities, and deploying our assets in new areas. For the year ended December 31, 2011, Chesapeake’s gross operated expenditures for rig relocation and logistics services were approximately $167.0 million, and our revenues from this segment represented approximately 77% of such expenditures. These amounts do not include Chesapeake’s expenditures for fluid hauling services, of which we currently provide only a small percentage.

Other Operations.    Compass Manufacturing, L.L.C., our manufacturing subsidiary, designs, engineers, fabricates, sells and installs natural gas compression units, accessories and equipment used in the production, treatment and processing of oil and natural gas. As of March 31, 2012, we had the capacity to manufacture up to up to 150 compressor units per quarter, or approximately 85,000 horsepower in the aggregate per quarter. Expansion opportunities for Compass include the manufacture of other types of oilfield equipment that are used in our oilfield rentals business. For the year ended December 31, 2011, Chesapeake’s gross operated expenditures for compressor purchases were approximately $87.5 million, and we provided Chesapeake with approximately 66% of its compressor manufacturing needs.

 

 

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Our Competitive Strengths

We believe that we have the following competitive strengths:

Our relationship with Chesapeake.    For nearly eight years, Chesapeake, our founder and principal customer, has maintained the nation’s most active drilling program, based on rig count. For the years ended December 31, 2009, 2010 and 2011, Chesapeake drilled 1,212, 1,445 and 1,662 gross operated oil and natural gas wells, respectively, and made $5.2 billion, $7.9 billion and $13.3 billion, respectively, of gross operated drilling and completion expenditures. As of December 31, 2011, Chesapeake had total estimated net proved reserves of 18.8 tcfe, which includes approximately 545 mmbbls of liquids, and was operating 162 drilling rigs to develop its inventory of approximately 39,000 risked net drill sites. We anticipate that a significant portion of the demand for our services in future years will come from Chesapeake’s exploitation of this large backlog of drilling locations, approximately 20 years’ worth at current drilling levels.

The chart below shows the average number of rigs drilling for Chesapeake during 2009, 2010 and 2011 compared to its most active competitors.

 

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Source: RigData–The Land Rig Newsletter Biweekly Report (excludes operating rigs that are in the process of rigging up or mobilization).

Looking forward, Chesapeake’s gross operated drilling and completion expenditure budgets for 2012 and 2013 are expected to be approximately $11.0 billion and $12.0 billion, respectively. Chesapeake’s industry-leading acreage position and active drilling program provide us with significant growth opportunities. Our relationship with Chesapeake, which gives us unique insights into our principal customer’s current and future oilfield services needs, positions us to operate efficiently, maintain industry-leading asset utilization and continue to improve our margins and creates incentives for Chesapeake to use our services.

 

 

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Significant revenue growth opportunities.    Chesapeake’s current and future oilfield services needs provide us with significant growth opportunities. As shown in the table below, revenues from our hydraulic fracturing and oilfield rentals segments in 2011 represented less than 1% and approximately 19%, respectively, of Chesapeake’s gross operated expenditures for these services, which is well below our objective of providing up to two-thirds of Chesapeake’s overall expected need for these services.

 

Segment(1)

   2011 Revenues
(in millions)(2)
     Chesapeake’s 2011 Gross
Operated Expenditures

(in millions)
     As a Percentage
of Chesapeake’s
Gross Operated
Expenditures
 

Drilling

   $ 855       $ 1,725         50

Hydraulic Fracturing

   $ 13       $ 3,486         0

Oilfield Rentals

   $ 246       $ 1,266         19

 

(1) See Note 14 to our audited consolidated financial statements included elsewhere in this prospectus for additional information about our reportable segments.
(2) Drilling and oilfield rentals segment revenues include third-party revenues. Hydraulic fracturing includes ancillary support services.

In addition, within our drilling and oilfield trucking segments, we currently provide Chesapeake with a small percentage of its needs for drilling-related services and fluid hauling services, providing us with additional growth opportunities. We will also have the opportunity to increase the scope of our service offerings to Chesapeake and its partners and to grow with Chesapeake, whose drilling and completion expenditures have increased by an average of 27% year over year since 2006. We believe that Chesapeake’s oilfield services demand and its incentives to use our services will provide us with the opportunity to grow our business significantly with relatively low risk of over-expansion.

 

 

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Industry-leading asset utilization.    Chesapeake’s 20-year backlog of drilling locations, many of which are in unconventional liquids plays, provides us with a unique opportunity to keep our assets highly utilized for years to come. We believe that Chesapeake’s incentives to use our services, combined with our objective of matching our productive capacity to meet up to two-thirds of Chesapeake’s expected overall needs for our services, will allow us to maintain industry-leading asset utilization levels through industry cycles. Additionally, Chesapeake’s drilling activity levels over time have been more stable than those of its peers. For example, in the twelve-month period ended September 30, 2009, one of the most challenging periods in the recent history of our industry, the U.S. onshore industry rig count decreased by 1,308 rigs, or 50%, while Chesapeake’s operated rig count, which includes third-party rigs, decreased by only 53 rigs, or 34%. During that same period, Chesapeake’s utilization of our rigs increased by six rigs, from 71 to 77, or 8%. The utilization rates of our other assets are correlated with our rig utilization rates because the well drilling performed by our rigs creates demand for most of the other services we provide. The chart below shows our drilling rig utilization over the last four years as compared with the U.S. industry onshore average.

 

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Source: RigData and Nomac active rig counts.

Additionally, our services agreement with Chesapeake guarantees the utilization of a portion of our drilling rig and hydraulic fracturing fleets through October 2016, with an annual evergreen thereafter. While we believe the utilization of our assets will remain at a level significantly higher than the minimum utilization rates provided for in the services agreement, the guaranteed utilization provides us with downside protection in our traditionally cyclical industry.

 

 

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Enhanced operational efficiencies.    Our unique relationship with Chesapeake creates operational efficiencies that our competitors cannot replicate. We have access to the activity forecasts prepared by Chesapeake and we maintain close communications with Chesapeake regarding its service needs, allowing us to efficiently provide timely, tailored, “just-in-time” service to Chesapeake. As the graph below indicates, we drill wells for Chesapeake and its partners on average approximately 10% faster than our competitors do.

 

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Source: Chesapeake internal reports based on wells spudded in 2011.

Our ability to align our operations and forecasts with Chesapeake incentivizes it to use our services, provides us with cost savings and efficient deployment of capital and allows us to provide services at an overall cost that is attractive to Chesapeake and its partners. Our relationship with Chesapeake also provides us with the support of a large, well-known parent-sponsor which we believe benefits us in dealing with suppliers, lenders, capital providers and others that a similarly sized standalone service company could not replicate. Finally, we believe that Chesapeake’s workplace reputation, which was recently recognized on FORTUNE’s 100 Best Companies to Work For® list as the best among energy production companies, and our stable asset utilization levels have allowed us to build a well-trained, safe and efficient workforce of over 5,000 employees and to maintain a lower employee turnover rate compared to industry averages.

Diversified, high quality asset base.    Our modern and well maintained assets are capable of providing unique operational advantages to Chesapeake. A substantial majority of our drilling rig fleet has been newly fabricated or refurbished since 2001, and substantially all of our rigs have been updated with the equipment necessary for horizontal drilling in today’s unconventional resource plays. We expect to have an additional 30 of our proprietary, fit-for-purpose PeakeRigs operating in the next six years, which will utilize state-of-the-art technology to improve drilling efficiency and will be rated 1,000 horsepower or greater. We also have an initiative underway to repower our drilling rigs with dual fuel, diesel/natural gas (DNG) systems, which will reduce our customers’ costs through the utilization of natural gas during our rig operations. Our hydraulic fracturing assets are among the newest in the industry, with 100% of our fleet built in 2011 or later by manufacturers with strong reputations for producing durable equipment capable of withstanding the demanding conditions typically presented by unconventional reservoirs. Our oilfield rentals, oilfield trucking and natural gas compressor manufacturing assets are modern and well maintained. The quality of our asset base

 

 

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and our comprehensive maintenance program results in less downtime, lower operating costs and increased utilization of our assets, which is critical for drilling and hydraulic fracturing operations where assets are commonly utilized on a 24-hour per day, seven day per week basis.

Experienced management team.    We have an experienced and skilled management team which is led by our Chief Executive Officer, Jerry L. Winchester, who has over 30 years of industry experience, including 13 years of experience as the president and chief executive officer of Boots & Coots International Well Control, Inc. (“Boots & Coots”). Our management team, including Mr. Winchester, Cary D. Baetz, our Chief Financial Officer, James G. Minmier, President of Nomac Drilling, L.L.C., Zachary M. Graves, President of Thunder Oilfield Services, L.L.C., William R. Stanger, President of Performance Technologies, L.L.C., and Alan D. Lavenue, President of Compass Manufacturing, L.L.C., collectively has over a century of oilfield services experience with prominent oilfield service companies such as Halliburton Company, Boots & Coots, Helmerich & Payne, Inc., Schlumberger Limited, Precision Drilling Corporation, Bronco Drilling Company, Inc. and Exterran Holdings, Inc. The remainder of our management team is comprised of seasoned operating, financial and administrative executives with extensive experience in and knowledge of the oilfield services industry. Our management team has operated through numerous oilfield services cycles and provides us with valuable experience and a detailed understanding of customer requirements.

Our Business Strategy

Our goal is to maximize shareholder value by profitably building a leading oilfield services company through leveraging our relationship with Chesapeake, the most active driller of new oil and natural gas wells in the U.S., to achieve our objective of providing up to two-thirds of Chesapeake’s overall expected needs for our current and future services and maintain industry-leading utilization rates. We plan to pursue the following strategic objectives to achieve this goal.

Grow our asset base.    We intend to aggressively grow our asset base, particularly our hydraulic fracturing fleets, oilfield rental inventory and drilling-related services, in order to achieve our objective of increasing our productive capacity to meet up to two-thirds of Chesapeake’s expected need for our services. We have placed substantial orders for additional new hydraulic fracturing units and expect to have eight fleets with approximately 315,000 horsepower in the aggregate operating by the end of 2012 and 12 fleets with approximately 450,000 horsepower in the aggregate operating by the end of 2013. Our drilling, hydraulic fracturing and oilfield rentals segments provide our highest margins and highest returns on invested capital relative to the other segments in which we operate. We are focused on increasing the revenues of these segments by growing our assets and expanding into the markets necessary to meet higher percentages of Chesapeake’s needs for these services, particularly the liquids-rich plays in which Chesapeake is now most active. During 2012 and 2013, we plan to make $1.1 billion to $1.2 billion of growth capital expenditures, in addition to amounts budgeted for the acquisition of presently leased rigs, and these expenditures will allow us to meet a greater percentage of Chesapeake’s needs and solidify our position as one of the largest U.S. onshore oilfield services companies.

Focus on full utilization of our assets.    Our oilfield service assets have traditionally maintained high utilization rates. For example, the utilization of our drilling rigs has averaged between approximately 95% and 99% since 2008. The utilization rates of our other assets are directly correlated with our rig utilization rates because the well drilling performed by our rigs creates demand for most of the other services we provide. Our industry-leading asset utilization rates result from our strategy of growing in tandem with Chesapeake and serving as a substantial provider of oilfield services to Chesapeake and its partners. We plan to maintain our industry-leading utilization rates as we continue

 

 

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to grow by growing our productive capacity to meet up to two-thirds of Chesapeake’s overall expected need for our services. We believe this strategy, combined with Chesapeake’s incentives to use our services, will continue to result in high utilization rates for our assets throughout industry cycles.

Focus on improving margins.    We plan to continue to improve our margins by leveraging our relationship with Chesapeake to decrease costs and make our business more efficient. Our relationship with Chesapeake enables us to operate more efficiently than our competitors by providing us with exclusive access to data that allows us to align our operations and projections with those of Chesapeake, to efficiently provide Chesapeake with timely, tailored, “just-in-time” services and to anticipate and quickly react to industry trends. As a result, our management team can focus its efforts on delivering efficient, high-quality services to Chesapeake and its partners rather than on marketing our services and managing through the cyclicality of oilfield activity and commodity prices. Additionally, we plan to continue to evolve our product and service offerings to include a larger percentage of higher margin offerings. We also believe that our new management team, which is exclusively dedicated to our operations and collectively has over a century of experience in the oilfield services industry, will enable us to better capitalize on existing efficiencies and identify further opportunities to maximize our margins. For example, since July 2011, our new management team has increased the gross margins in our drilling segment through various cost saving initiatives by approximately 20%, while at the same time improving our safety and productivity metrics.

Capitalize on opportunities to provide additional services.    As the driller of a substantial majority of Chesapeake’s wells, we play a central role in the planning and execution of Chesapeake’s drilling program. As a result of this role, we are uniquely positioned to cross-sell our other service offerings to Chesapeake, observe the service offerings of other third-party service providers that are present at the well site and evaluate expansion opportunities. We plan to use this role to focus our growth on high margin product and services offerings. While we already provide Chesapeake with approximately two-thirds of its drilling rig needs, we plan to increase the percentage of drilling-related services that we provide, such as directional drilling, mud logging and geosteering. In our hydraulic fracturing segment, we believe that expansion opportunities exist not only through expanding our fleets but also by vertically integrating our operations through the integration of sand reserves, sand processing operations and railcar, truck and other logistics assets. We also plan to continue to grow our oilfield rentals segment, where our inventory of tools and equipment can be expanded to include additional drilling and completion rental tools. We have a significant growth capital expenditure budget of between $1.1 billion and $1.2 billion over the next two years with which to develop such business lines. These amounts are in addition to amounts budgeted for the acquisition of presently leased rigs. We believe that targeting the development of these high margin product and services offerings through geographic expansion, vertical integration and asset additions will provide us with a greater return on our investment in our assets and cash flows for future growth.

Continued focus on safety.    Our relationship with Chesapeake provides us with enhanced utilization across industry cycles, which in turn reduces employee turnover, increases safety and drives superior results. In addition, the continuity of working relationships between our employees and Chesapeake provides for greater communication and data sharing at our drill sites, which we believe results in safer working conditions for employees. We are focused on hiring, training and retaining high-quality employees. As a result of our strong emphasis on training and safety protocols for our employees, we believe we have a superior safety record and reputation. We have a strong and improving Total Recordable Incidence Rate (TRIR) safety record even as our employee base has more than doubled over the past two years. From 2009 to 2011, our TRIR dropped by approximately 36%. In addition, all of our field-based employees are eligible to receive incentive pay based on satisfying safety standards, which we believe motivates them to continually maintain quality and safety.

 

 

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Industry Overview

Oilfield service companies provide services that are used by exploration and production companies, or E&P companies, in connection with the exploration for and the development and production of hydrocarbons. E&P companies operating in the U.S. include independent E&P companies, such as Chesapeake, U.S.-based major integrated oil and gas companies, such as ExxonMobil, ChevronTexaco and ConocoPhillips, and international major integrated oil and gas companies, such as Shell, Total S.A., BP America, CNOOC Limited and Statoil. Demand for domestic onshore oilfield services is a function of the willingness of E&P companies to make operating and capital expenditures to explore for, develop and produce hydrocarbons in the U.S. When oil or natural gas prices increase, E&P companies generally increase their capital expenditures, resulting in greater revenues and profits for oilfield service companies. Likewise, significant decreases in the prices of those commodities typically lead E&P companies to reduce their capital expenditures, which lowers the demand for oilfield services.

Oil and natural gas prices rose to record levels in 2008 and then began to decline in late 2008 in conjunction with the widespread economic recession. While the price of oil rebounded somewhat in 2009 and continued to rise throughout 2010 and 2011, the price of natural gas has continued to fall since 2009 largely due to discoveries of vast new natural gas resources in the U.S. The WTI Cushing spot price of a barrel of crude oil reached an all-time high of $145.29 per barrel in July 2008 and then dropped sharply by the end of the year, falling to as low as $31.41 per barrel on December 22, 2008 before trending upward again by late 2009 and reaching $92.19 in January 2011. During 2011, oil prices generally remained high, averaging $95.05 per barrel through December 31, 2011, due to increased demand, generally flattening international supply and geopolitical tensions. This trend has continued in 2012 with current oil prices above $100 per barrel. On the other hand, from the beginning of 2009 through March 31, 2012, U.S. Henry Hub natural gas prices generally declined from a starting price of $5.40 per mmbtu to an ending price of $2.00 per mmbtu.

 

 

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The number of drilling rigs under contract in the U.S. decreased in 2009 but rebounded in 2010 and has remained high since then relative to historical levels, according to data compiled by Baker Hughes Incorporated. This has remained the case despite a dramatic decrease in the price of natural gas over the same period, suggesting a weakening in the traditional correlation between natural gas prices and U.S. onshore drilling rig counts. We believe this decrease in correlation is attributable to several factors, including the discovery of potentially large oil and liquids-rich unconventional plays onshore in the U.S., the increasing presence in U.S. onshore plays of major U.S. and international integrated E&P companies that are typically less reactive to short-term price fluctuations than independent E&P companies, the presence of term contracts for certain types of oilfield services, the need by operators to commence drilling activities in order to establish production and avoid the expiration of oil and natural gas leases, and the more regimented approach to developing unconventional plays characterized by continuous hydrocarbon accumulations. Additionally, we believe that the weakening correlation between natural gas prices and U.S. onshore rig counts is partially attributable to the prevalence of joint ventures for the development of U.S. unconventional plays, many of which include a drilling “carry” that is paid by the joint venture partner and used by the operator to pay for a portion of the cost of drilling and completing the well. Chesapeake, for example, has entered into several such joint ventures since 2008 with companies such as Total S.A., CNOOC Limited, Statoil, BP America and Plains Exploration & Production Company that have provided more than $9.0 billion of drilling carries to Chesapeake.

 

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Source: Baker Hughes Incorporated and Bloomberg.

 

 

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In response to historically low natural gas prices, a number of E&P companies, including Chesapeake, have announced that they are reducing dry natural gas drilling and production and redirecting their activities and capital toward currently more economic liquids-rich plays. Liquids-rich plays are those that are characterized by production of predominantly oil and natural gas liquids such as ethane, propane, butane and iso-butane, which are used as energy sources and manufacturing feedstocks, and the prices of which have historically been highly correlated with oil prices rather than natural gas prices. As a result, we expect the trend toward liquids-focused drilling to continue. The proportion of rigs in the U.S. drilling for liquids versus natural gas has also increased steadily over the past few years and, in April 2011, for the first time since 1993, the number of rigs drilling for liquids surpassed the number of rigs drilling for natural gas.

 

LOGO

 

Source: Baker Hughes Incorporated

Trends that we believe are affecting, and will continue to affect, our industry include:

Drilling and developing unconventional U.S. hydrocarbon resources.    Due to the maturity of conventional U.S. oil and natural gas reservoirs, the relative abundance of undeveloped unconventional resources and the cost advantage of developing unconventional resources, an increasing proportion of U.S. oil and natural gas production is coming from unconventional resources, which include shale formations. Since the beginning of 2008, producers have spent substantial amounts acquiring properties in unconventional resource plays in the U.S., including approximately $20.0 billion spent by Chesapeake, as advances in horizontal drilling and completion technologies have made the development of many unconventional resources economically attractive.

Horizontal wells are typically drilled in these unconventional formations and tend to involve a higher degree of service intensity associated with their initial drilling and completion, and we believe that these wells will also ultimately require a high degree of service intensity over their lifetime. The U.S. horizontal and directional rig count has risen from 705 (or 42% of the total) at the beginning of 2007 to 1,413 (or 71% of the total) for the week ending March 30, 2012, according to Baker Hughes Incorporated. In addition to an increase in the number of horizontal wells drilled in the U.S., the length of well laterals has increased and the intervals between fracturing stages have decreased over the past several years. The longer laterals and increasing number of fracturing stages have enhanced recoveries and lowered field development costs while causing the number of fracturing stages to grow at a faster rate than the horizontal rig count, creating an increased demand for completion related services.

 

 

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Increased drilling in liquids-rich formations.    There is increasing horizontal drilling- and completion-related activity in liquids-rich formations such as the Eagle Ford, Utica, Bakken and Niobrara Shales and various other unconventional liquids-rich plays in Texas and Oklahoma, including the Wolfcamp, Bone Spring, Granite Wash, Cleveland and Tonkawa sands and the Mississippi Lime. In January 2012, Chesapeake announced its plan to curtail its dry gas drilling and production activities and redirect capital to its liquids-rich plays. We believe that the oil and natural gas liquids content in these plays significantly enhances the returns for Chesapeake and its partners relative to opportunities in dry gas basins due to the significant disparity between oil and natural gas prices on a British thermal unit (btu) basis. Furthermore, we believe that oil and natural gas liquids prices tend to exhibit less volatility than natural gas prices due to the global nature of the crude oil market and the more localized market for natural gas. We believe that the higher price of liquids relative to natural gas, as well as liquids’ reduced pricing volatility will continue over the near- to medium-term, resulting in increasing demand for services in liquids-rich basins and a reduction in the variability of demand for oilfield services generally.

High asset utilization and tight labor and equipment market.    Many of the unconventional reservoirs in the U.S. are deep, high-pressure and challenging environments, factors that increase the demand for skilled workers and high-quality oilfield services. Equipment manufacturers have had difficulty meeting the demand for services equipment, resulting in high asset utilization levels across the industry. In addition, demand for skilled workers is high and the supply is limited. We believe these trends will continue to keep supply tight in our industry for the foreseeable future.

Complex technologies, techniques and equipment.    The development of unconventional oil and natural gas resources is driving the need for complex new technologies, completion techniques and equipment designed to increase recovery rates, lower production costs and accelerate field development. These needs have spurred the development of more technologically advanced, higher-margin oilfield services that are required to economically produce oil and natural gas from unconventional resources. In addition to rigs with adequate horsepower and top drives, in many cases directional drilling systems are necessary to enable the operator to steer the drill bit into the appropriate section of the reservoir, and advanced technologies, such as the latest hydraulic fracturing, proppant and fluids technologies, are needed for completion of the wells.

Constrained supply of hydraulic fracturing sand.    The sand used as a proppant in hydraulic fracturing operations must meet certain size and other specifications in order to be suitable for hydraulic fracturing purposes. Securing access to hydraulic fracturing sand that conforms to the specifications established by the American Petroleum Institute is increasingly important to suppliers and customers of hydraulic fracturing services. Rising unconventional production in the U.S. will continue to support demand for hydraulic fracturing sand, which is used extensively in domestic unconventional basins. The hydraulic fracturing sand market is driven by the overall demand for oil and natural gas production and, in particular, horizontal drilling of oil and natural gas wells. Accordingly, the demand for hydraulic fracturing sand has grown significantly, paralleling the heightened development activity in unconventional reservoirs. We believe the industry is currently experiencing both high demand and limited supply of hydraulic fracturing sand. As we continue to grow our hydraulic fracturing business, we plan to mitigate this risk by vertically integrating our operations through the integration of sand reserves, sand processing operations and logistics assets such as storage and transload, railcar, trucking and other assets.

 

 

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Organizational Structure

Formation Transactions

On October 25, 2011, Chesapeake completed the process of reorganizing its oilfield services subsidiaries and operations as subsidiaries of COS LLC and commenced providing all of its oilfield services through COS LLC.

We were incorporated in Oklahoma on April 10, 2012 and have not engaged in any business or other activities except in connection with our formation and the offering transactions described in this prospectus.

Offering Transactions

Concurrently with the closing of this offering, we will issue                 shares of our Class A common stock to the purchasers in this offering in exchange for net proceeds of approximately $            . We will use the net proceeds from this offering to acquire newly issued Class A units from COS LLC, representing     % of COS LLC’s outstanding membership units. COS LLC will use the following approximate amounts of such net proceeds for the following purposes:

 

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$             million will be used by COS LLC to make a capital contribution to COO, which will use such cash to repay outstanding borrowings under its revolving bank credit facility and for general corporate purposes;

 

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$             million will be used by COS LLC to repay the balance outstanding under an intercompany promissory note with Chesapeake; and

 

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$             million will be used to make a distribution to Chesapeake Operating, Inc., a wholly owned subsidiary of Chesapeake.

If the underwriters exercise their option to purchase additional shares of Class A common stock in full in connection with this offering, we will use the additional net proceeds to acquire additional Class A units from COS LLC, and COS LLC will distribute any such proceeds to Chesapeake. For more information regarding the transactions occurring in connection with the offering, see “Organizational Structure—Offering Transactions.”

Chesapeake’s existing membership units in COS LLC will be reclassified as “Class B units” and will represent     % of COS LLC’s outstanding membership units immediately following this offering. In addition, we will issue to Chesapeake a number of shares of our Class B common stock equal to the number of Class B units of COS LLC held by Chesapeake immediately following this offering in exchange for the payment by Chesapeake of the aggregate par value of such shares. Each share of Class B common stock will entitle Chesapeake to             votes on matters to be voted on by our shareholders generally until the first time that the number of shares of our Class B common stock outstanding constitutes less than         % of the number of all shares of our common stock outstanding. For more information regarding the terms of our common stock, see “Description of Capital Stock.”

Immediately following this offering:

 

  Ÿ  

We will be appointed as the sole managing member of COS LLC;

 

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We will hold                     Class A units of COS LLC representing approximately     % of COS LLC’s total outstanding membership units (or                     and     %, respectively, if the underwriters exercise their option to purchase additional shares of Class A common stock in full);

 

 

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  Ÿ  

Chesapeake will own                     Class B units of COS LLC representing approximately     % of COS LLC’s total outstanding membership units (or                     and     %, respectively, if the underwriters exercise their option to purchase additional shares of Class A common stock in full);

 

  Ÿ  

Chesapeake, through its ownership of our Class B common stock, will have     % of the combined voting power of all of our common stock and, through its ownership of Class B units of COS LLC, will hold approximately     % of the economic interest in our business (or     % voting power in us and a     % economic interest if the underwriters exercise their option to purchase additional shares of Class A common stock in full); and

 

  Ÿ  

the purchasers in this offering will own                 shares of our Class A common stock, representing     % of the combined voting power of all of our common stock and, through our ownership of Class A units of COS LLC, approximately     % of the economic interest in our business (or     % voting power in us and a     % economic interest if the underwriters exercise their option to purchase additional shares of Class A common stock in full).

Following this offering, Chesapeake may exchange its Class B units in COS LLC for shares of our Class A common stock on a one-for-one basis. When Chesapeake exchanges a Class B unit of COS LLC for a share of our Class A common stock, we will automatically redeem and cancel a corresponding share of our Class B common stock. See “Certain Relationships and Related Party Transactions—Amended and Restated Operating Agreement of COS LLC—Exchange Rights.”

 

 

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The following chart summarizes our holding company structure and anticipated ownership immediately following this offering and the transactions described above (assuming no exercise by the underwriters of their option to purchase additional shares of Class A common stock). For more information, please see “Organizational Structure.”

 

LOGO

Our Relationship with Chesapeake

Following this offering, we will be a holding company and our sole material asset will be the Class A units of COS LLC that we own. As the sole managing member of COS LLC, we will control all of the business and affairs of COS LLC and its subsidiaries. Initially, Chesapeake, as the holder of all

 

 

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of the shares of our Class B common stock, will have     % of the combined voting power of all of our outstanding common stock (or     % if the underwriters exercise their option to purchase additional shares of Class A common stock in full). Therefore, upon the closing of this offering and for the foreseeable future thereafter, Chesapeake will continue to control our business and will be able to control all matters requiring the approval of our shareholders, including the election of directors and the approval of significant corporate transactions. See “Organizational Structure.”

Additionally, we are a party to several agreements with Chesapeake, including a master services agreement and services agreement pursuant to which we provide services and supply materials and equipment to Chesapeake and under which Chesapeake has agreed to operate a minimum number of our drilling rigs and to utilize our hydraulic fracturing equipment for a minimum number of fracturing stages per month.

In addition, we and Chesapeake are parties to an administrative services agreement and a facilities lease agreement. These agreements were entered into in the context of an affiliated relationship and, consequently, may not be as favorable to us as they might have been if we had negotiated them with unaffiliated third parties. For a more comprehensive discussion of the agreements that we have entered into with Chesapeake and certain of its affiliates, please see “Certain Relationships and Related Party Transactions.” For a discussion of the risks related to our relationship with Chesapeake, please read “Risk Factors—Risks Relating to Our Relationship with Chesapeake.”

Tax Receivable Agreement

In connection with the consummation of this offering, we will enter into a tax receivable agreement with Chesapeake pursuant to which we will agree to pay to Chesapeake 85% of the amount of cash savings, if any, in federal, state and local income taxes that we actually realize (or in certain circumstances are deemed to realize) as a result of (a) the tax basis increases in the assets of COS LLC that arose from certain recent acquisitions by us; (b) any tax basis increase resulting from COS LLC’s distribution of offering proceeds to Chesapeake; (c) the tax basis increases resulting from exchanges by Chesapeake of its Class B units of COS LLC for shares of our Class A common stock; (d) additional deductions allocated to us pursuant to Section 704(c) of the Internal Revenue Code of 1986, as amended (the “Code”) to reflect the difference between the fair market value and the adjusted tax basis of COS LLC’s assets as of the date of this offering and (e) imputed interest deemed to be paid by us as a result of, and additional tax basis arising from, payments under the tax receivable agreement. We will retain the benefit of the remaining 15% of these cash savings. See “Certain Relationships and Related Party Transactions—Tax Receivable Agreement.”

Corporate Information

Our principal executive offices are located at 6100 North Western Avenue, Oklahoma City, Oklahoma 73118, and our telephone number is (405) 848-8000. Our website is located at www.cosok.com. Information on our website or any other website is not incorporated by reference herein and does not constitute a part of this prospectus.

 

 

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The Offering

 

Class A common stock offered by us

                 shares of our Class A common stock.

 

Class A common stock outstanding after the offering

                 shares of our Class A common stock (or                  shares of Class A common stock if the underwriters exercise their option to purchase additional shares of Class A common stock in full).

 

Class B common stock outstanding after the offering

                 shares of our Class B common stock (or                  shares of Class B common stock if the underwriters exercise their option to purchase additional shares of Class A common stock in full).

 

Underwriters’ option to purchase additional shares of Class A common stock in this offering

We have granted the underwriters an option, exercisable for 30 days from the date of this prospectus, to purchase up to                      additional shares of our Class A common stock.

 

Use of proceeds

We are offering the Class A common stock to be sold in this offering. Assuming no exercise of the underwriters’ option to purchase additional shares of Class A common stock, we expect to receive approximately $             million of net proceeds from the sale of the Class A common stock offered based upon the assumed initial public offering price of $             per share (the midpoint of the price range set forth on the cover page of this prospectus), after deducting underwriting discounts and estimated offering expenses. Each $1.00 increase (decrease) in the public offering price would increase (decrease) our net proceeds by approximately $             million.

 

  We intend to use the net proceeds from this offering to acquire newly issued Class A units from COS LLC, representing     % of COS LLC’s outstanding membership units. COS LLC will use approximately $             million of such net proceeds to make a capital contribution to COO, which will use such cash to repay outstanding borrowings under its revolving bank credit facility and for general corporate purposes, approximately $             million of such net proceeds to repay the balance outstanding under an intercompany promissory note with Chesapeake and approximately $             million of such net proceeds to make a distribution to Chesapeake Operating, Inc., a wholly owned subsidiary of Chesapeake.

 

 

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  We intend to use any additional proceeds we receive if the underwriters exercise their option to purchase additional shares of Class A common stock to acquire additional Class A units from COS LLC, and COS LLC will distribute any such proceeds to Chesapeake.

 

  Chesapeake has advised us that it intends to use the net proceeds distributed to it by COS LLC to repay borrowings under its corporate revolving bank credit facility, under which it may re-borrow from time to time and does so for general corporate purposes, including land, drilling and other costs. See “Use of Proceeds.”

 

Voting rights

Each share of our Class A common stock will entitle its holder to one vote on all matters to be voted on by shareholders generally.

 

  Each share of our Class B common stock will entitle its holder to                          votes on all matters to be voted on by shareholders generally until the first time that the number of shares of our Class B common stock outstanding constitutes less than                          % of the number of all shares of our common stock outstanding. From and after that time, each share of our Class B common stock will entitle its holder to one vote. Through its ownership of our Class B common stock, Chesapeake will hold shares of our common stock having     % of the combined voting power of all of our common stock outstanding (or      % if the underwriters exercise their option to purchase additional shares of Class A common stock in full). As a result, for the foreseeable future following this offering, Chesapeake will be able to exercise control over matters requiring the approval of our shareholders, including the election of our directors and the approval of significant corporate transactions.

 

  Holders of our Class A common stock and Class B common stock will vote together as a single class on all matters presented to shareholders for their vote or approval, except as otherwise required by law. See “Description of Capital Stock.”

 

Economic interest

Immediately following this offering, the purchasers in this offering will own in the aggregate a         % economic interest in our business through our ownership of Class A units of COS LLC and Chesapeake will own a         % economic interest in our business through its ownership of Class B units of COS LLC (or a         % economic interest and a         % economic interest, respectively, if the underwriters exercise their option to purchase additional shares of our Class A common stock in full).

 

 

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Lock-up

We, all of our directors and officers and Chesapeake will enter into a lock-up agreement with the underwriters pursuant to which we and it may not, without the prior written approval of Goldman, Sachs & Co., offer, sell, contract to sell or otherwise dispose of or hedge our Class A common stock or securities convertible into or exchangeable for our Class A common stock, subject to certain exceptions, for a period of 180 days after the date of this prospectus, subject to extension in certain circumstances. See “Underwriting” for a discussion of the circumstances in which this 180-day period may be extended.

 

Exchange and registration rights

Each Class B unit of COS LLC will be exchangeable for a share of our Class A common stock as described under “Certain Relationships and Related Party Transactions—Amended and Restated Operating Agreement of COS LLC—Exchange Rights.”

 

  Pursuant to a registration rights agreement that we will enter into with Chesapeake, we will agree to file a registration statement for the sale of the shares of our Class A common stock that are issuable upon exchange of Class B units of COS LLC upon request and cause that registration statement to be declared effective by the U.S. Securities and Exchange Commission (“SEC”) as soon as practicable thereafter. See “Certain Relationships and Related Party Transactions—Registration Rights Agreement” for a description of the timing and manner limitations on resales of these shares of our Class A common stock.

 

Dividend policy

After this offering, we do not anticipate paying cash dividends on our Class A common stock in the immediate future. Holders of our Class B common stock will not have the right to receive regular dividends. See “Dividend Policy.”

 

Proposed New York Stock Exchange symbol

“COS”

Unless otherwise indicated, the number of shares of Class A common stock outstanding after this offering and other information based thereon in this prospectus excludes:

 

  Ÿ  

shares of our Class A common stock which may be issued upon the exercise of the underwriters’ option to purchase additional shares of Class A common stock and the corresponding number of Class A units of COS LLC that we would acquire with the net proceeds therefrom; and

 

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shares of our Class A common stock reserved for issuance upon exchange of Chesapeake’s Class B units of COS LLC that will be outstanding immediately after this offering.

 

 

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Risk Factors

An investment in our Class A common stock involves significant risks. Before investing in our Class A common stock, you should carefully consider all the information contained in this prospectus, including the information under the headings “Risk Factors” and “Cautionary Note Regarding Forward-Looking Statements.” Our business, financial condition and results of operations could be materially and adversely affected by many factors, including the following factors and the factors discussed in “Risk Factors” and elsewhere in this prospectus:

 

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We are dependent on Chesapeake for a substantial majority of our revenues. Therefore, we are indirectly subject to the business risks of Chesapeake. We have no control over Chesapeake’s business decisions and operations, and Chesapeake is under no obligation to adopt a business strategy that favors us;

 

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Demand for services in our industry is cyclical and depends on drilling and completion spending by Chesapeake and other E&P companies in the U.S., and the level of such activity is volatile;

 

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Competition in our industry or increases in the supply of drilling rigs or hydraulic fracturing units could decrease the prices for our products and services and our revenues;

 

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Shortages or increases in the costs of the equipment we use in our operations could adversely affect our growth plans and our operations in the future;

 

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Shortages or increases in the costs of the products we use in our operations could adversely affect our results of operations;

 

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The loss of key executives could adversely affect our ability to effectively operate and manage our business;

 

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Increased labor costs or the unavailability of skilled workers could hurt our operations;

 

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We participate in a capital intensive industry. We may not be able to finance future growth of our operations or future acquisitions;

 

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Delays in obtaining permits by our customers for their operations could impair our business;

 

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Any future decreases in the rate at which oil or natural gas reserves are discovered or developed could decrease the demand for our services;

 

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Our business involves many hazards and operational risks, some of which may not be fully covered by insurance. If a significant accident or event occurs for which we are not adequately insured, our operations and financial results could be adversely affected;

 

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Federal and state legislative and regulatory initiatives relating to hydraulic fracturing could restrict or make more difficult our hydraulic fracturing operations or could increase our or Chesapeake’s operating costs;

 

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We are subject to federal, state and local laws and regulations regarding issues of health, safety, climate change and protection of the environment. Under these laws and regulations, we may become liable for penalties, damages or costs of remediation or other corrective measures. Any changes in laws or government regulations could increase our costs of doing business; and

 

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Chesapeake has the option to terminate our services agreement if Chesapeake no longer controls us.

 

 

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Summary Historical and Pro Forma Financial Data

The following tables set forth summary historical and unaudited pro forma financial data of COS LLC and its predecessors. The summary historical financial data as of December 31, 2011 and for each of the years ended December 31, 2009, 2010 and 2011 is derived from the audited consolidated financial statements included elsewhere in this prospectus. Our historical consolidated financial statements for periods and as of dates prior to our October 25, 2011 reorganization were prepared on a “carve-out” basis from Chesapeake and are intended to represent the financial results of Chesapeake’s oilfield service operations for those periods. The summary historical financial data is not necessarily indicative of results to be expected in future periods. Our summary historical financial data should be read together with the historical consolidated financial statements and related notes thereto and “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” each included elsewhere in this prospectus.

The summary unaudited pro forma financial data as of December 31, 2011 and for the year ended December 31, 2011 is derived from the audited consolidated financial statements included elsewhere in this prospectus and includes pro forma adjustments to give effect to certain transactions that occurred during the year ended December 31, 2011, and the transactions associated with our formation and this offering. Our summary unaudited pro forma financial data should be read together with the unaudited pro forma consolidated financial statements and related notes thereto included elsewhere in this prospectus.

The financial statements of COS Inc. have not been presented in this prospectus as it is a newly incorporated entity, has had no business transactions or activities to date and has no (or nominal) assets or liabilities.

 

    Years Ended December 31,  
    COS LLC Historical     Pro Forma
Combined (3)
 
    2009     2010     2011     2011  
                      (Unaudited)  
   

(In thousands)

 

Income Statement Data:

       

Revenues, including revenues from affiliates

  $ 650,279      $ 815,756      $ 1,303,496      $ 1,366,066   

Operating costs

    556,008        666,924        987,032        1,036,399   

Depreciation and amortization

    70,429        106,425        171,908        180,236   

General and administrative costs, including expenses from affiliates

    17,735        25,312        37,074        45,902   

Losses (gains) on sales of property and equipment

    (1,551     (854     (3,571     (3,546

Impairments

    26,797 (1)      9        2,729        3,408   
 

 

 

   

 

 

   

 

 

   

 

 

 

Operating income (loss)

    (19,139     17,940        108,324        103,667   
 

 

 

   

 

 

   

 

 

   

 

 

 

Interest expense, including expenses from affiliates

    (23,453     (38,511     (65,072  

Losses from equity investee

    (164     (2,243     —          —     

Other income (expense)

    (283     211        (2,464     (1,979
 

 

 

   

 

 

   

 

 

   

 

 

 

Total other expense

    (23,900     (40,543     (67,536  
 

 

 

   

 

 

   

 

 

   

 

 

 

Income (loss) before income taxes

    (43,039     (22,603     40,788     

Income tax expense (benefit)

    (2,656     (3,751     21,030     
 

 

 

   

 

 

   

 

 

   

 

 

 

Net income (loss)

    (40,383     (18,852     19,758     
 

 

 

   

 

 

   

 

 

   

 

 

 

Less: Net Loss Attributable to Noncontrolling Interest

    —          (639     (154  
 

 

 

   

 

 

   

 

 

   

 

 

 

Net Income (Loss) Attributable to COS Holdings, L.L.C.

  $ (40,383   $ (18,213   $ 19,912      $     
 

 

 

   

 

 

   

 

 

   

 

 

 

Other Financial Data:

       

Adjusted EBITDA(2)(unaudited)

  $ 76,089      $ 121,488      $ 276,926      $     

Capital expenditures (including acquisitions)

  $ 325,895      $ 269,769      $ 738,354      $     

 

 

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     As of December 31, 2011  
     Actual      Pro Forma(4)  
            (Unaudited)  
     (In thousands)  

Balance Sheet Data:

     

Cash

   $ 2,360       $     

Total property and equipment, net

   $ 1,225,580       $ 1,225,580   

Total assets

   $ 1,598,582       $     

Total long-term debt

   $ 1,050,674       $     

Total equity

   $ 181,782       $     

 

(1) We recorded an impairment to goodwill in the amount of $19.8 million and an impairment of long-lived assets in the amount of $7.0 million for the year ended December 31, 2009.
(2) “Adjusted EBITDA” is a non-GAAP financial measure that we define as net income before interest, taxes, depreciation and amortization, as further adjusted to add back gain or loss on sale of property and equipment and impairments. “Adjusted EBITDA,” as used and defined by us, may not be comparable to similarly titled measures employed by other companies and is not a measure of performance calculated in accordance with GAAP. Adjusted EBITDA should not be considered in isolation or as a substitute for operating income, net income or loss, cash flows provided by operating, investing and financing activities, or other income or cash flow statement data prepared in accordance with GAAP. However, our management believes Adjusted EBITDA may be useful to an investor in evaluating our operating performance because this measure:

 

  Ÿ  

is widely used by investors in the oilfield services industry to measure a company’s operating performance without regard to items excluded from the calculation of such measure, which can vary substantially from company to company depending upon accounting methods, book value of assets, capital structure and the method by which assets were acquired, among other factors;

 

  Ÿ  

is a financial measurement that, with certain negotiated adjustments, will be reported to our lenders pursuant to our forthcoming revolving bank credit facility and will be used in the financial covenants in our revolving bank credit facility; and

 

  Ÿ  

is used by our management for various purposes, including as a measure of performance of our operating entities and as a basis for strategic planning and forecasting.

 

     There are significant limitations to using Adjusted EBITDA as a measure of performance, including the inability to analyze the effect of certain recurring and non-recurring items that materially affect our net income or loss, and the lack of comparability of results of operations of different companies.

 

     The following table presents a reconciliation of the non-GAAP financial measure of Adjusted EBITDA to the GAAP financial measure of net income (loss):

 

     Years Ended December 31,  
     COS LLC Historical     Pro Forma
Combined
 
     2009     2010     2011     2011  
     (In thousands)  

Net income (loss)

   $ (40,383   $ (18,852   $ 19,758      $     

Interest expense

     23,453        38,511        65,072     

Income tax expense (benefit)

     (2,656     (3,751     21,030     

Depreciation and amortization

     70,429        106,425        171,908        180,236   

Impairments

     26,797        9        2,729        3,408   

Gains on sales of property and equipment

     (1,551     (854     (3,571     (3,546
  

 

 

   

 

 

   

 

 

   

 

 

 

Adjusted EBITDA

   $ 76,089      $ 121,488      $ 276,926      $     
  

 

 

   

 

 

   

 

 

   

 

 

 

 

(3) Includes pro forma adjustments to give effect to (a) the acquisition of Bronco Drilling Company, Inc. in June 2011, (b) our transfer of certain land and buildings to Chesapeake in October 2011, (c) the issuance by COO of $650.0 million of 6.625% Senior Notes due 2019 in October 2011 and the use of the net proceeds therefrom to repay a portion of an intercompany promissory note owed to Chesapeake, (d) COO’s entry into, and borrowings under, our revolving bank credit facility in November 2011 and (e) our reorganization in connection with, and the closing of, this offering and the application of the estimated net proceeds as described in “Use of Proceeds”.
(4) Includes pro forma adjustments to give effect to our reorganization in connection with, and the closing of, this offering and the application of the estimated net proceeds as described in “Use of Proceeds.”

 

 

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RISK FACTORS

An investment in our Class A common stock involves risks. You should carefully consider the risks described below before making an investment decision. Our business, financial condition or results of operations could be materially adversely affected by any of these risks. The trading price of our Class A common stock could decline due to any of these risks, and you may lose all or part of your investment. The risks discussed below are not the only risks we face. We may experience additional risks and uncertainties not currently known to us, or as a result of developments occurring in the future. Conditions that we currently deem to be immaterial may also materially and adversely affect our business, financial condition, cash flows and results of operations.

Risks Relating to Our Business

We are dependent on Chesapeake for a substantial majority of our revenues. Therefore, we are indirectly subject to the business risks of Chesapeake. We have no control over Chesapeake’s business decisions and operations, and Chesapeake is under no obligation to adopt a business strategy that favors us.

Historically, we have provided substantially all of our oilfield services to Chesapeake and its partners. During 2009, 2010 and 2011, Chesapeake and its partners accounted for approximately 95%, 96% and 94% of our revenues, respectively, and we expect to derive a substantial majority of our revenues from Chesapeake for the foreseeable future. If Chesapeake ceases to engage us on terms that are attractive to us, particularly after the expiration of our services agreement with it, our business, financial condition and results of operations will be materially adversely affected. Accordingly, we are indirectly subject to the business risks of Chesapeake, some of which are the following:

 

  Ÿ  

the volatility of oil and natural gas prices, which could have a negative effect on the value of its oil and natural gas properties, its drilling programs, its ability to finance its operations and its willingness to spend capital for exploration and development activities;

 

  Ÿ  

the availability of capital on an economic basis to fund its exploration and development activities;

 

  Ÿ  

its discovery rate of new oil and natural gas reserves and the speed at which it develops such reserves;

 

  Ÿ  

its drilling and operating risks, including potential environmental liabilities;

 

  Ÿ  

transportation capacity constraints and interruptions; and

 

  Ÿ  

adverse effects of governmental and environmental regulation.

Our relationship with Chesapeake presents a number of additional risks to us. Please read “—Risks Related to Our Relationship with Chesapeake.”

Demand for services in our industry is cyclical and depends on drilling and completion spending by Chesapeake and other E&P companies in the U.S., and the level of such activity is volatile.

Demand for services in our industry is cyclical, and we depend on Chesapeake’s and our other customers’ willingness to make expenditures to explore for, develop and produce oil and natural gas in the U.S. Our customers’ willingness to undertake these activities depends largely upon prevailing industry conditions that are influenced by numerous factors over which we have no control, including:

 

  Ÿ  

prices, and expectations about future prices, of oil and natural gas;

 

  Ÿ  

domestic and foreign supply of and demand for oil and natural gas;

 

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  Ÿ  

the cost of exploring for, developing, producing and delivering oil and natural gas;

 

  Ÿ  

available pipeline, storage and other transportation capacity;

 

  Ÿ  

lead times associated with acquiring equipment and products and availability of qualified personnel;

 

  Ÿ  

the expected rates of decline in production from existing and prospective wells;

 

  Ÿ  

the discovery rates of new oil and natural gas reserves;

 

  Ÿ  

federal, state and local regulation of hydraulic fracturing and other oilfield activities, including public pressure on governmental bodies and regulatory agencies to regulate our industry;

 

  Ÿ  

the availability of water resources and suitable proppants in sufficient quantities for use in hydraulic fracturing operations;

 

  Ÿ  

the availability, capacity and cost of disposal and recycling services for used hydraulic fracturing fluids;

 

  Ÿ  

political instability in oil and natural gas producing countries;

 

  Ÿ  

advances in exploration, development and production technologies or in technologies affecting energy consumption;

 

  Ÿ  

the price and availability of alternative fuels and energy sources; and

 

  Ÿ  

uncertainty in capital and commodities markets and the ability of oil and natural gas producers to raise equity capital and debt financing.

Anticipated future prices for natural gas and crude oil are a primary factor affecting spending and drilling activity by E&P companies, including Chesapeake. Lower prices or volatility in prices for oil and natural gas typically decrease spending and drilling activity, which can cause rapid and material declines in demand for our services and in the prices we are able to charge for our services. Worldwide political, economic and military events as well as natural disasters and other factors beyond our control contribute to oil and natural gas price levels and volatility and are likely to continue to do so in the future.

Any prolonged substantial reduction in oil and natural gas prices would likely affect oil and natural gas production levels and, therefore, would affect demand for and prices of the services we provide. While we have a services agreement with Chesapeake providing for minimum utilization of certain of our equipment, that agreement provides that we will receive market rates for our services, and, consequently, the prices we are able to charge will fluctuate with market conditions. A material decline in oil and natural gas prices or drilling activity levels or sustained lower prices or activity levels could have a material adverse effect on our business, financial condition, results of operations and cash flow.

For example, deterioration in the global economic environment commencing in the latter part of 2008 and continuing throughout 2009 caused the oilfield services industry to cycle into a downturn. Declines in prices for oil and natural gas experienced during this period caused many E&P companies to announce reductions in capital budgets for future periods. Likewise, many E&P companies, including Chesapeake, recently have announced plans to reduce drilling in plays characterized by higher concentrations of dry natural gas. Although many of these companies, including Chesapeake, have also announced that they will refocus their drilling activities on liquids-rich plays, an overall reduction in the demand for oilfield services could still occur, which would adversely affect the prices that we are able to charge, and the demand, for our services. Additionally, we may incur costs and have downtime as we redeploy equipment and personnel from dry natural gas plays to liquids-rich plays.

 

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Spending by E&P companies can also be impacted by conditions in the capital markets. Limitations on the availability of capital, or higher costs of capital, for financing expenditures may cause Chesapeake and other E&P companies to make additional reductions to capital budgets in the future even if oil prices remain at current levels or natural gas prices increase from current levels. Any such cuts in spending will curtail drilling and completion programs as well as discretionary spending on well services, which may result in a reduction in the demand for our services, the rates we can charge and the utilization of our assets. Moreover, reduced discovery rates of new oil and natural gas reserves, or a decrease in the development rate of reserves, in our market areas, whether due to increased governmental regulation, limitations on exploration and drilling activity or other factors, could also have a material adverse impact on our business, financial condition, results of operations and cash flow, even in a stronger oil and natural gas price environment.

Competition in our industry or increases in the supply of drilling rigs or hydraulic fracturing units could decrease the prices for our products and services and our revenues.

The market for oilfield services in which we operate is highly competitive. Contracts are traditionally awarded on the basis of competitive bids or direct negotiations with customers. The competitive environment has intensified as recent mergers among E&P companies have reduced the number of available customers. The fact that drilling rigs and other vehicles and pieces of oilfield services equipment are mobile and can be moved from one market to another in response to market conditions heightens the competition in the industry.

In addition, there has been a substantial increase in the supply of land drilling rigs in the U.S. over the past five years, and a number of competitors have announced that they are expanding their hydraulic fracturing fleets or entering into the hydraulic fracturing market for the first time. An increase in the supply of land drilling rigs, whether through new construction or refurbishment, or an increase in the supply of hydraulic fracturing units could decrease revenue rates and utilization rates. We do not have a fixed price contract with Chesapeake. Thus, if competition or other factors decrease market prices for the products and services we provide, Chesapeake could require us to lower the prices we charge to it. A reduction in the rates we charge would adversely affect our revenues and profitability. Such adverse effect on our revenue and profitability could be further aggravated by any downturn in oil and natural gas prices.

Shortages or increases in the costs of the equipment we use in our operations could adversely affect our growth plans and our operations in the future.

Our business strategy calls for us to grow rapidly. We may not be able to achieve our growth targets due to delays in procuring needed equipment. We generally do not have long term contracts in place that provide for the delivery of equipment needed to meet our growth plans. We could experience delays in the delivery of the equipment that we have ordered and its placement into service due to factors that are beyond our control. New federal regulations regarding diesel engines, demand by other oilfield service companies and numerous other factors beyond our control could adversely affect our ability to procure equipment we have not yet ordered that is needed to meet our growth plans or cause the prices of such equipment to increase.

Shortages or increases in the costs of the products we use in our operations could adversely affect our results of operations.

We do not have long-term contracts with the third-party suppliers of many of the products that we use in large volumes in our operations, such as the proppants and chemicals we use in our hydraulic fracturing operations and the fuel we use in our equipment and vehicles. During periods in which oilfield services are in high demand, the availability of the key products used in our industry decreases

 

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and the price of such products increases. We are dependent on a small number of suppliers for key raw materials and finished products. Our reliance on a small number of suppliers could increase the difficulty of obtaining such products in the event of shortage in our industry. Shortages of such products could cause us to curtail our operations or could affect our results of operations if price increases cannot be passed on to our customers, or have a combination of both effects, which could have a material adverse effect on our business, financial condition or results of operations.

Although we currently have plans to vertically integrate our hydraulic fracturing operations by integrating sand mines, sand processing facilities and additional logistics assets, there is no assurance that we will be able to do so successfully. If we are unsuccessful at vertically integrating, we will continue to depend on third-party suppliers for dry sand and transportation systems and therefore will be unable to reduce the logistical and supply-chain challenges inherent in our business.

Additionally, our hydraulic fracturing operations require a significant supply of water. Our water requirements are met by Chesapeake or our other customers from sources on or near their sites, but our customers may not have access to water in sufficient quantities to perform hydraulic fracturing operations due to reasons beyond their or our control, such as drought, water rationing and regulatory actions. These risks are more pronounced in semi-arid regions where we operating extensively. An inability to secure an adequate supply of water for our operations could have a material adverse effect on our business, financial condition or results of operations.

The loss of key executives could adversely affect our ability to effectively operate and manage our business.

We are dependent upon the efforts and skills of our executives to manage and grow our business. In addition, our development and expansion will require additional experienced management, operations and technical personnel. We cannot assure you that we will be able to retain these employees, and the loss of the services of one or more of our key executives could increase our exposure to the other risks described in this “Risk Factors” section. We do not maintain key man insurance on any of our personnel.

Increased labor costs or the unavailability of skilled workers could hurt our operations.

We are dependent upon an available pool of skilled employees to maintain and grow our business. We compete with other oilfield services businesses and other employers to attract and retain qualified personnel with the technical skills and experience required to provide the highest quality service. The demand for skilled workers is high and the supply is limited, and a shortage in the labor pool of skilled workers or other general inflationary pressures or changes in applicable laws and regulations could make it more difficult for us to attract and retain personnel and could require us to enhance our wage and benefits packages.

Although our employees are not covered by a collective bargaining agreement, union organizational efforts could occur and, if successful, could increase our labor costs. A significant increase in the wages paid by competing employers or the unionization of groups of our employees could result in increases in the wage rates that we must pay. Likewise, laws and regulations to which we are subject, such as the Fair Labor Standards Act, which governs such matters as minimum wage, overtime and other working conditions, can increase our labor costs or subject us to liabilities to our employees. We cannot assure you that labor costs will not increase. Increases in our labor costs or unavailability of skilled workers could impair our capacity and diminish our profitability, having a material adverse effect on our business, financial condition, results of operations and cash flow.

Historically, our industry has experienced a high annual employee turnover rate. We believe that the high turnover rate is attributable to the nature of the work, which is physically demanding and

 

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performed outdoors, and to the volatility and cyclical nature of the oilfield service industry. As a result, workers may choose to pursue employment in fields that offer a more desirable work environment at wage rates that are competitive with ours. We cannot assure that we will be able to recruit, train and retain an adequate number of workers to replace departing workers. The inability to maintain an adequate workforce could have a material adverse effect on our business, financial condition, results of operations and cash flow.

We participate in a capital intensive industry. We may not be able to finance future growth of our operations or future acquisitions.

Our activities require substantial capital expenditures. In the past, we have relied on capital infusions by Chesapeake to meet our liquidity needs. We do not anticipate that Chesapeake will need to make these capital infusions in the future. However, if our cash flow from operating activities and borrowings under our revolving bank credit facility are not sufficient to fund our capital expenditure budget, we would be required to fund these expenditures through debt or equity or alternative financing plans, such as:

 

  Ÿ  

refinancing or restructuring our debt;

 

  Ÿ  

selling assets; and/or

 

  Ÿ  

reducing or delaying acquisitions or capital investments, such as acquisitions of additional revenue-generating equipment and refurbishments of our rigs and related equipment.

However, if debt and equity capital or alternative financing plans are not available or are not available on economically attractive terms, we would be required to curtail our capital spending, and our ability to grow our business and sustain or improve our profits may be adversely affected. Our ability to refinance or restructure our debt will depend on the condition of the capital markets and our and Chesapeake’s financial condition at such time, among other things. Any refinancing of our debt could be at higher interest rates and may require us to comply with more onerous covenants, which could further restrict our business operations. In addition, any failure to make payments of interest and principal on our outstanding indebtedness on a timely basis or to satisfy our liquidity needs would likely result in a reduction of our credit rating, which could harm our ability to incur additional indebtedness. Any failure to make payments under the operating subleases for our drilling rigs would result in a default under such sublease and could cause us to lose the use of the affected drilling rigs. The terms of existing or future debt instruments may restrict us from adopting some of these alternatives. Chesapeake has significant long-term indebtedness, and we could experience an increase in our borrowing costs or difficultly accessing, or an inability to access, the capital markets based on adverse developments affecting Chesapeake. See “—Risks Relating to our Relationship With Chesapeake—Chesapeake’s level of indebtedness could adversely affect our ability to grow our business, as well as our credit ratings and profile.” Any of the foregoing consequences could materially and adversely affect our business, financial condition, results of operations and prospects.

Delays in obtaining permits by our customers for their operations could impair our business.

Our customers are required to obtain permits from one or more governmental agencies in order to perform drilling and/or completion activities. Such permits are typically required by state agencies but can also be required by federal and local governmental agencies. The requirements for such permits vary depending on the location where such drilling and completion activities will be conducted. As with all governmental permitting processes, there is a degree of uncertainty as to whether a permit will be granted, the time it will take for a permit to be issued and the conditions which may be imposed in connection with the granting of the permit. Certain regulatory authorities have delayed or suspended the issuance of permits while the potential environmental impacts associated with issuing such permits

 

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can be studied and appropriate mitigation measures evaluated. Permitting delays, an inability to obtain new permits or revocation of our or our customers’ current permits could cause a loss of revenue and potentially have a materially adverse effect on our operations.

Any future decreases in the rate at which oil or natural gas reserves are discovered or developed could decrease the demand for our services.

Reduced discovery rates of new oil and natural gas reserves, or a decrease in the development rate of reserves, in our market areas, whether due to increased governmental regulation, limitations on exploration and drilling activity or other factors, could have a material adverse impact on our business even in a stronger oil and natural gas price environment.

Our business involves many hazards and operational risks, some of which may not be fully covered by insurance. If a significant accident or event occurs for which we are not adequately insured, our operations and financial results could be adversely affected.

Our operations are subject to many hazards and risks, including the following:

 

  Ÿ  

accidents resulting in serious bodily injury and the loss of life or property;

 

  Ÿ  

liabilities from accidents or damage by our fleet of trucks, rigs and other equipment;

 

  Ÿ  

pollution and other damage to the environment;

 

  Ÿ  

blow-outs, the uncontrolled flow of natural gas, oil or other well fluids into or through the environment, including onto the ground or into the atmosphere, surface waters or an underground formation; and

 

  Ÿ  

fires and explosions.

If any of these hazards occur, they could result in suspension of operations, damage to or destruction of our equipment and the property of others, or injury or death to our personnel or third parties and could expose us to substantial liability or losses. The frequency and severity of such incidents will affect operating costs, insurability and relationships with customers, employees and regulators. In addition, these risks may be greater for us upon the acquisition of another company that has not allocated significant resources and management focus to safety and has a poor safety record.

We are not fully insured against all risks inherent in our business. For example, we do not have any business interruption/loss of income insurance that would provide coverage in the event of damage to any of our equipment or facilities. Although we are insured for environmental pollution resulting from environmental accidents that occur on a sudden and accidental basis, we may not be insured against all environmental accidents that might occur, some of which may result in toxic tort claims. If a significant accident or event occurs for which we are not adequately insured, it could adversely affect our operations and financial condition. Furthermore, we may not be able to maintain or obtain insurance of the type and amount we desire at reasonable rates. As a result of market conditions, premiums and deductibles for certain of our insurance policies may substantially increase. In some instances, certain insurance could become unavailable or available only for reduced amounts of coverage.

Federal and state legislative and regulatory initiatives relating to hydraulic fracturing could restrict or make more difficult our hydraulic fracturing operations or could increase our or Chesapeake’s operating costs.

It is customary in our industry to recover oil and natural gas from deep shale and other formations through horizontal drilling and hydraulic fracturing. Hydraulic fracturing is the process of creating or expanding cracks, or fractures, in hydrocarbon bearing formations by pumping water, sand and other additives under high pressure into the formation.

 

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The hydraulic fracturing process is typically regulated by state oil and natural gas commissions. Several states, including Pennsylvania, Texas, Colorado, Montana, New Mexico and Wyoming, have adopted, and other states are considering adopting, regulations that could impose more stringent permitting, public disclosure, and/or well construction requirements on hydraulic fracturing operations. New York has sought to ban fracturing activities altogether. In addition to state laws, some local municipalities have adopted or are considering adopting land use restrictions, such as city ordinances, that may restrict or prohibit the performance of well drilling in general and/or hydraulic fracturing in particular.

Additionally, the U.S. Environmental Protection Agency (the “EPA”) has asserted federal regulatory authority over the hydraulic fracturing activities involving diesel fuel (specifically, when diesel fuel is utilized in the stimulation fluid) under the Safe Drinking Water Act and is completing the process of drafting guidance documents related to this newly asserted regulatory authority. There are also certain governmental studies either underway or being proposed that focus on deep shale and other formation completion and production practices, including hydraulic fracturing. Depending on the outcome of these studies, federal and state legislatures and agencies may seek to further regulate such activities.

Certain environmental and other groups have suggested that additional federal, state and local laws and regulations may be needed to more closely regulate the hydraulic fracturing process. We cannot predict whether additional federal, state or local laws or regulations will be enacted in the future and, if so, what actions any such laws or regulations would require or prohibit. If additional levels of regulation or permitting requirements were imposed through the adoption of new laws and regulations, our business and operations could be subject to delays, increased operating costs or process prohibitions. Compliance by us and Chesapeake and the costs and burdens associated therewith or the consequences of any failure to comply by us with these regulations could have a material adverse effect on our business, financial condition, results of operations and cash flow.

We are subject to federal, state and local laws and regulations regarding issues of health, safety, climate change and protection of the environment. Under these laws and regulations, we may become liable for penalties, damages or costs of remediation or other corrective measures. Any changes in laws or government regulations could increase our costs of doing business.

Our operations are subject to stringent federal, state and local laws and regulations relating to, among other things, protection of natural resources, wetlands, endangered species, the environment, health and safety, waste management, waste disposal and transportation of waste and other materials. Our operations pose risks of environmental liability, including leakage from our operations to surface or subsurface soils, surface water or groundwater. Some environmental laws and regulations may impose strict liability, joint and several liability, or both. Therefore, in some situations, we could be exposed to liability as a result of our conduct that was lawful at the time it occurred or the conduct of, or conditions caused by, third parties without regard to whether we caused or contributed to the conditions. Actions arising under these laws and regulations could result in the shutdown of our operations, fines and penalties, expenditures for remediation or other corrective measures, and claims for liability for property damage, exposure to hazardous materials, exposure to hazardous waste or personal injuries. Sanctions for noncompliance with applicable environmental laws and regulations also may include the assessment of administrative, civil or criminal penalties, revocation of permits, temporary or permanent cessation of operations in a particular location and issuance of corrective action orders. Such claims or sanctions and related costs could cause us to incur substantial costs or losses and could have a material adverse effect on our business, financial condition, results of operations and cash flow. Additionally, an increase in regulatory requirements on oil and gas exploration and completion activities could significantly delay or interrupt our operations.

 

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Various state governments and regional organizations are considering enacting new legislation and promulgating new regulations governing or restricting the emission of greenhouse gases from stationary sources such as our equipment and operations. Legislative and regulatory proposals for restricting greenhouse gas emissions or otherwise addressing climate change could require us to incur additional operating costs and could adversely affect demand for the oil and natural gas that we drill for and help produce. The potential increase in our operating costs could include new or increased costs to obtain permits, operate and maintain our equipment and facilities, install new emission controls on our equipment and facilities, acquire allowances to authorize our greenhouse gas emissions, pay taxes related to our greenhouse gas emissions and administer and manage a greenhouse gas emissions program. Moreover, incentives to conserve energy or use alternative energy sources could reduce demand for oil and natural gas.

The EPA regulates air emissions from certain off-road diesel engines that are used by us to power equipment in the field. Under these Tier IV regulations, we are required to retrofit or retire certain engines, and we are limited in the number of non-compliant off-road diesel engines we can purchase. Tier IV engines are costlier and are not yet widely available. Until Tier IV-compliant engines that meet our needs are available, these regulations could limit our ability to acquire a sufficient number of engines to expand our fleet and to replace existing engines as they are taken out of service. Further, the Tier IV regulations may result in increased costs as we continue to grow.

Laws protecting the environment generally have become more stringent over time and we expect them to continue to do so, which could lead to material increases in our costs for future environmental compliance and remediation.

Chesapeake has the option to terminate our services agreement if Chesapeake no longer controls us.

Chesapeake is not subject to any contractual obligation to maintain an ownership interest in us except for a limited period, as described in “Underwriting,” during which it is not permitted to sell any of our Class A common stock until 180 days after the date of this prospectus. Chesapeake has the option to terminate our services agreement in the event it no longer controls us. Under our services agreement with Chesapeake, Chesapeake has guaranteed certain utilization levels for our drilling rigs and hydraulic fracturing fleets. If Chesapeake no longer controls us, it may no longer be required to utilize our services and it will have less incentive to do so.

Part of our growth strategy is focused on our hydraulic fracturing operations, which is subject to certain risks.

The expansion of our hydraulic fracturing operations is a major component of our growth strategy. We began hydraulic fracturing operations in the fourth quarter of 2011 and we currently own four hydraulic fracturing fleets. Congress and several states are considering proposed legislation and regulations which, if passed, would impose additional requirements or restrictions on hydraulic fracturing operations. See “—Federal and state legislative and regulatory initiatives relating to hydraulic fracturing could restrict or make more difficult our hydraulic fracturing operations or could increase our or Chesapeake’s operating costs.” In addition, an increase in the supply of hydraulic fracturing units or a reduction in demand for hydraulic fracturing services could require us to lower the prices we charge for such services, which might make expansion of such business line less attractive. See “—Competition in our industry or increases in the supply of drilling rigs or hydraulic fracturing units could decrease the prices for our products and services and our revenues.” Finally, we may experience a lack of availability of hydraulic fracturing equipment or key products, such as proppants and chemicals, that we use in our hydraulic fracturing operations. See “—Shortages or increases in the costs of the products we use in our operations could adversely affect our results of operations.” The occurrence of these and other events

 

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and conditions could cause us to be unable to grow our hydraulic fracturing operations as projected and be unable to meet our overall growth objectives.

Growth in our business could strain our resources and increase our operating expenses.

We have experienced rapid growth, and our business strategy calls for us to continue to grow rapidly. Our growth may require us, among other things, to:

 

  Ÿ  

raise additional capital;

 

  Ÿ  

expand and improve our operational and financial procedures, infrastructure, systems and controls;

 

  Ÿ  

hire additional management, accounting or other personnel;

 

  Ÿ  

improve our financial and management information systems;

 

  Ÿ  

expand, train and manage a larger workforce;

 

  Ÿ  

improve the coordination among our operating, sales and marketing, financial, accounting and management personnel; and

 

  Ÿ  

potentially assume unknown liabilities.

Additionally, growth into new geographic areas presents additional complexities, such as securing facilities for our operations and ensuring compliance with local regulations. Our inability to manage growth effectively or to maintain the quality of our services could have a material adverse effect on our business, financial condition or results of operations.

Severe weather could have a material adverse effect on our business.

Adverse weather can directly impede our operations. Repercussions of severe weather conditions may include:

 

  Ÿ  

curtailment of services;

 

  Ÿ  

weather-related damage to facilities and equipment, resulting in suspension of operations;

 

  Ÿ  

inability to deliver equipment, personnel and products to job sites in accordance with contract schedules; and

 

  Ÿ  

loss of productivity.

These constraints could delay our operations and materially increase our operating and capital costs. Unusually warm winters or cold summers may also adversely affect the demand for our services by decreasing the demand for natural gas. Our operations in semi-arid regions can be affected by droughts and other lack of access to water used in our operations.

We may not be successful in identifying, making and integrating acquisitions.

A component of our business strategy is to make selective acquisitions that will strengthen our core services or presence in selected markets. The success of this strategy will depend, among other things, on our ability to identify suitable acquisition candidates, to negotiate acceptable financial and other terms, to timely and successfully integrate acquired businesses or assets and to retain the key personnel and the customer base of acquired businesses. Any future acquisitions could present a number of risks, including but not limited to:

 

  Ÿ  

incorrect assumptions regarding the future results of acquired operations or assets or expected cost reductions or other synergies expected to be realized as a result of acquiring operations or assets;

 

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  Ÿ  

failure to integrate successfully the operations or management of any acquired operations or assets in a timely manner;

 

  Ÿ  

failure to retain or attract key employees; and

 

  Ÿ  

diversion of management’s attention from existing operations or other priorities.

If we are unable to identify, make and successfully integrate acquired businesses, we may be unable to meet our growth objectives.

Restrictions in our credit facilities and indentures could adversely affect our business, financial condition and results of operations.

The operating and financial restrictions in our revolving bank credit facility and in the indenture governing our 2019 Senior Notes and any future financing agreements entered into by us or COO could restrict our ability to finance future operations or capital needs, to meet our growth objectives or to otherwise expand and pursue our business activities. For example, the revolving bank credit facility and the indenture limit COO’s and its subsidiaries’ ability to, among other things:

 

  Ÿ  

incur additional debt or issue guarantees;

 

  Ÿ  

incur or permit certain liens to exist;

 

  Ÿ  

make certain investments, acquisitions or other restricted payments;

 

  Ÿ  

dispose of assets;

 

  Ÿ  

engage in certain types of transactions with affiliates;

 

  Ÿ  

merge, consolidate or transfer all or substantially all of our assets; and

 

  Ÿ  

prepay certain indebtedness.

Furthermore, our revolving bank credit facility contains covenants requiring COO to maintain a maximum consolidated leverage ratio and a minimum interest coverage ratio.

A failure to comply with the covenants in the revolving bank credit facility, the indenture or any future indebtedness could result in an event of default, which, if not cured or waived, would permit the exercise of remedies against COO that would be likely to have a material adverse effect on our business, financial condition, results of operations and cash flow. The existence of these covenants may also prevent or delay us from pursuing business opportunities that we believe would otherwise benefit us, which could adversely affect our ability to meet our growth objectives.

We may be able to incur more debt and long-term lease obligations in the future.

Our revolving bank credit facility and the indenture governing our 2019 Senior Notes do not prohibit us, and restrict but do not prohibit COO and its subsidiaries, from incurring additional indebtedness and other obligations in the future. If we incur additional debt, the related risks that we and our subsidiaries face could intensify. As of December 31, 2011, after giving effect to this offering and the application of the estimated net proceeds therefrom as described herein, as if each such transaction had occurred on that date, we would have had $            million of long-term indebtedness.

In addition, the revolving bank credit facility and the indenture governing the 2019 Senior Notes do not restrict us, and restrict but do not prohibit COO and its subsidiaries, from entering into sale-leaseback transactions and capital lease obligations. In lieu of incurring debt, we have and may continue to raise capital through sale-leaseback transactions. In a series of transactions since 2006, our predecessor sold an aggregate of 93 drilling rigs and related equipment for total proceeds of approximately $801.8 million. We are currently subleasing these rigs and related equipment from Chesapeake. All of these leases have been accounted for as operating leases and, as a result, our

 

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obligations under these leases are not reflected on our balance sheet. As of December 31, 2011, the total amount of obligations under our operating leases was $502.3 million, which primarily consisted of leases arising from the sale-leaseback transactions involving the rigs described above. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Commitments and Contingencies” and Note 6 “Commitments and Contingencies” to our audited consolidated financial statements included elsewhere in this prospectus.

Our level of indebtedness and long-term lease obligations will have several important effects on our future operations, including, without limitation:

 

  Ÿ  

requiring us to dedicate a significant portion of our cash flow from operations to support the payment of debt service and rental expense;

 

  Ÿ  

increasing our vulnerability to adverse changes in general economic and industry conditions, and putting us at a competitive disadvantage relative to competitors that have less fixed obligations and more cash flow to devote to their businesses;

 

  Ÿ  

limiting our ability to obtain additional financing for working capital, capital expenditures, general corporate and other purposes; and

 

  Ÿ  

limiting our flexibility in operating our business and preventing us from engaging in certain transactions that might otherwise be beneficial to us.

Any of these factors could result in a material adverse effect on our business, financial condition, results of operations, business prospects.

Changes in trucking regulations may increase our costs and negatively impact our results of operations.

For the transportation and relocation of our drilling rigs and oilfield services equipment and our fluid hauling operations, we operate trucks and other heavy equipment. We therefore are subject to regulation as a motor carrier by the U.S. Department of Transportation and by various state agencies, whose regulations include certain permit requirements of highway and safety authorities. These regulatory authorities exercise broad powers over our trucking operations, generally governing such matters as the authorization to engage in motor carrier operations, safety, equipment testing and specifications and insurance requirements. The trucking industry is subject to possible regulatory and legislative changes that may impact our operations, such as by requiring changes in fuel emissions limits, the hours of service regulations that govern the amount of time a driver may drive or work in any specific period, limits on vehicle weight and size and other matters. On May 21, 2010, President Obama signed an executive memorandum directing the National Highway Traffic Safety Administration and the Environmental Protection Agency to develop new, stricter fuel efficiency standards for medium- and heavy-duty trucks. On September 15, 2011, the NHTSA and the EPA published regulations that regulate fuel efficiency and greenhouse gas emissions from medium- and heavy-duty trucks, beginning with vehicles built for model year 2014. As a result of these regulations, we may experience an increase in costs related to truck purchases and maintenance, impairment of equipment productivity, decrease in the residual value of these vehicles and an increase in operating expenses. Proposals to increase federal, state or local taxes, including taxes on motor fuels, are also made from time to time, and any such increase would increase our operating costs. We cannot predict whether, or in what form, any legislative or regulatory changes applicable to our trucking operations will be enacted and to what extent any such legislation or regulations could increase our costs or otherwise adversely affect our business or operations.

 

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New technology may cause us to become less competitive.

The oilfield service industry is subject to the introduction of new drilling and completion techniques and services using new technologies, some of which may be subject to patent protection. As competitors and others use or develop new technologies in the future, we may be placed at a competitive disadvantage. Further, we may face competitive pressure to implement or acquire certain new technologies at a substantial cost. Some of our competitors have greater financial, technical and personnel resources that may allow them to enjoy technological advantages and implement new technologies before we can. We cannot be certain that we will be able to implement new technologies or products on a timely basis or at an acceptable cost. Thus, limits on our ability to effectively use and implement new and emerging technologies may have a material adverse effect on our business, financial condition, results of operations and cash flow.

Conservation measures and technological advances could reduce demand for oil and natural gas.

Fuel conservation measures, alternative fuel requirements, increasing consumer demand for alternatives to oil and natural gas, technological advances in fuel economy and energy generation devices could reduce demand for oil and natural gas. Management cannot predict the impact of the changing demand for oil and natural gas services and products, and any major changes may have a material adverse effect on our business, financial condition, results of operations and cash flows.

We have operated at a loss in the past, and there is no assurance of our profitability in the future.

We had net losses during 2009 and 2010, and we may incur operating losses and experience negative operating cash flow in the future. Negative operating results could adversely affect our ability to maintain our capital expenditure program, the trading price of our Class A common stock and our ability to pay dividends in the future.

Our operating history may not be sufficient for investors to evaluate our business and prospects.

We are a recently organized company with a short operating history that is experiencing significant growth. This may make it more difficult for investors to evaluate our business and prospects and to forecast our future operating results. The historical consolidated financial statements included in this prospectus for periods and as of the dates prior to our October 25, 2011 reorganization have been prepared on a “carve-out” basis from Chesapeake and may not be indicative our results of operations and financial condition had we operated as a standalone entity. This prospectus contains unaudited pro forma financial information derived by adjusting our historical consolidated financial statements to give effect to certain described transactions, but that pro forma financial information may not give you an accurate indication of what our actual results would have been if we had been formed at the beginning of the periods presented or of what our future results of operations are likely to be. Our future results will depend on our ability to efficiently manage our combined operations and execute our business strategy.

Risks Relating to Our Relationship with Chesapeake

As long as we are controlled by Chesapeake, your ability to influence the outcome of matters requiring shareholder approval will be limited.

After the completion of this offering, Chesapeake will own all of the outstanding shares of our Class B common stock, representing     % of the combined voting power of our Class A and Class B common stock. Each share of our outstanding Class B common stock is entitled to             votes per

 

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share, for as long as the number of shares of our Class B common stock outstanding constitutes at least     % of the total number of shares of our common stock outstanding. So long as Chesapeake holds at least     % of the total number of shares of our common stock outstanding, it will have voting control of our company. As long as Chesapeake has voting control of our company, it will have the ability to take many shareholder actions, including the election or removal of directors, irrespective of the vote of, and without prior notice to, any other shareholder. As a result, Chesapeake will have the ability to influence or control all matters affecting us, including:

 

  Ÿ  

the composition of our Board of Directors and, through our Board of Directors, decision-making with respect to our business direction and policies, including the appointment and removal of our officers;

 

  Ÿ  

any determinations with respect to acquisitions of businesses, mergers, or other business combinations;

 

  Ÿ  

the selection of the services that we will provide;

 

  Ÿ  

our acquisition or disposition of assets;

 

  Ÿ  

our capital structure;

 

  Ÿ  

changes to the agreements relating to our relationship with Chesapeake;

 

  Ÿ  

decisions as to how to interpret and perform obligations under the agreements relating to our relationship with Chesapeake;

 

  Ÿ  

our payment or non-payment of dividends on our common stock; and

 

  Ÿ  

determinations with respect to our tax returns.

Chesapeake’s interests may not be the same as, or may conflict with, the interests of our other shareholders. As a result, actions that Chesapeake takes with respect to us, as our controlling shareholder, may not be favorable to us or our other shareholders. In addition, this voting control may discourage transactions involving a change of control of our company, including transactions in which you, as a holder of our Class A common stock, might otherwise receive a premium for your shares over the then-current market price.

Chesapeake’s level of indebtedness could adversely affect our ability to grow our business, as well as our credit ratings and profile.

Chesapeake must devote a portion of its cash flows from operating activities to service its indebtedness, and such cash flows are therefore not available for further development activities, which may reduce Chesapeake’s need for our services. As of December 31, 2011, Chesapeake had long-term indebtedness of approximately $10.6 billion. The covenants contained in the agreements governing Chesapeake’s outstanding and future indebtedness may limit its ability to borrow additional funds for development and make certain investments, which also may reduce the demand Chesapeake has for our services.

Credit rating agencies such as Standard & Poor’s and Moody’s will likely consider Chesapeake’s debt ratings when considering our debt ratings, and investors may also consider those ratings because of Chesapeake’s ownership interest in us, the significant commercial relationships between Chesapeake and us and our reliance on Chesapeake for a substantial majority of our revenues. If one or more credit rating agencies were to downgrade the outstanding indebtedness of Chesapeake, we could experience an increase in our borrowing costs or difficulty accessing, or an inability to access, the capital markets. Such a development could also adversely affect our ability to grow our business and to make payments on our debt obligations.

 

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The interests of Chesapeake, in its capacity as our controlling shareholder and our largest customer, may be adverse to the interests of our other shareholders, and Chesapeake may resolve any potential conflicts of interest in a manner that is unfavorable to our other shareholders.

As our controlling shareholder and largest customer, Chesapeake will able to determine our business strategy and policies. Chesapeake may cause us to pursue a business strategy that favors Chesapeake’s oilfield services needs rather than a business strategy focused on maximizing returns to the holders of our Class A common stock. For example, Chesapeake may cause us to invest in and provide service lines that would otherwise be difficult for Chesapeake to source but that provide relatively low margins to us at the expense of service lines that would provide higher margins to us.

Other conflicts of interest that may arise between Chesapeake and us relating to our past and ongoing relationships include:

 

  Ÿ  

labor, tax, employee benefit, indemnification and other matters arising under our agreements and other relationships with Chesapeake;

 

  Ÿ  

employee recruiting and retention;

 

  Ÿ  

sales or distributions by Chesapeake of all or any portion of its ownership interest in us, which could be to one of our competitors; and

 

  Ÿ  

the interpretation, administration and enforcement of contractual and other rights between Chesapeake and us.

We cannot assure you that the interests of Chesapeake will coincide with the interests of the holders of our Class A common stock. We may not be able to resolve any potential conflicts, and, so long as Chesapeake continues to own a majority of the combined voting power of all of our outstanding common stock and remains a significant customer, it will continue to be able to effectively control our business and may resolve any such conflicts in a way that is unfavorable to the holders of our Class A common stock.

Additionally, Chesapeake from time to time makes investments in other companies, and it could hold interests in other companies that compete with us. For example, Chesapeake is an equity investor in FTS International, LLC, an oilfield services company that provides hydraulic fracturing services to E&P companies. Chesapeake could have conflicts of interest in its dealings with FTS International and us.

Any of these potential conflicts of interest could have a material adverse effect on our business, financial condition, results of operations and cash flow.

Certain agreements between us and Chesapeake were entered into in the context of an affiliated relationship and may not be fair to us.

While we believe that the master services agreement, services agreement, administrative services agreement, facilities lease agreement and other contractual agreements we have with Chesapeake are on terms that are representative of an arms-length transaction, those agreements were entered into in the context of an affiliated relationship. In addition, at the closing of this offering we will enter into a tax receivable agreement, an amended and restated operating agreement of COS LLC and a registration rights agreement with Chesapeake, each of which also will have been entered into in the context of our affiliated relationship. In addition, these agreements may be amended, and Chesapeake, as the holder of the substantial majority of the combined voting power of our common stock, will have control over our decision to agree to any such amendments, which could have terms

 

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that may not be representative of the terms of future agreements that we may enter into with unaffiliated third parties.

If our administrative services agreement with Chesapeake is terminated, or if Chesapeake fails to provide us with adequate services, we will have to obtain those services internally or through third-party arrangements.

We depend on Chesapeake to provide us certain general and administrative services and any additional services we may request pursuant to our administrative services agreement. The initial five-year term of the administrative services agreement, which ends October 25, 2016, will be extended for additional one-year periods unless we or Chesapeake provides one-year prior written notice of termination, subject to certain conditions and limitations. Though Chesapeake will agree to perform such services using no less than the level of care it uses in providing such services to itself and its other subsidiaries, if Chesapeake fails to provide us adequate services, or if the agreement is terminated for any reason, we will have to obtain these services internally or through third-party arrangements which may result in increased costs to us.

We will not have control over certain costs and expenses allocated to us by Chesapeake.

We have agreements with Chesapeake pursuant to which Chesapeake allocates certain expenses to us. Under our administrative services agreement with Chesapeake, in return for the general and administrative services provided by Chesapeake, we reimburse Chesapeake on a monthly basis for the overhead expenses incurred by Chesapeake on our behalf in accordance with its current allocation policy, which also includes actual out-of-pocket fees, costs and expenses incurred in connection with the provision of any of the services under the agreement, including the wages and benefits of Chesapeake employees who perform services on our behalf.

Under our facilities lease agreement with Chesapeake, in return for the use of certain yards and other physical facilities out of which we conduct our operations, we pay rent and our proportionate share of maintenance, operating expenses, taxes and insurance to Chesapeake on a monthly basis.

The costs allocated to us by these agreements with Chesapeake may be higher than the costs that we would incur if we obtained such services ourselves.

Our directors and executive officers who own shares of common stock of Chesapeake, who hold options to acquire common stock of Chesapeake or other Chesapeake equity-based awards or who hold positions with Chesapeake may have actual or potential conflicts of interest.

Ownership of shares of common stock of Chesapeake, options to acquire shares of common stock of Chesapeake and other equity-based securities of Chesapeake by certain of our directors and officers after this offering, and the presence of directors or officers of Chesapeake on our Board of Directors could create, or appear to create, potential conflicts of interest when those directors and officers are faced with decisions that could have different implications for Chesapeake than they do for us. Certain of our directors will hold director and/or officer positions with Chesapeake or beneficially own significant amounts of common stock of Chesapeake.

 

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After the completion of this offering, we will be a “controlled company” within the meaning of the NYSE rules and, as a result, will qualify for, and intend to rely on, exemptions from certain corporate governance requirements that provide protection to shareholders of other companies.

After the completion of this offering, Chesapeake will own more than 50% of the voting power of all then outstanding shares of our capital stock entitled to vote generally in the election of directors, and we will be a “controlled company” under the New York Stock Exchange (“NYSE”) corporate governance standards. As a controlled company, we intend to rely on certain exemptions from the NYSE standards that will enable us not to comply with certain NYSE corporate governance requirements, including the requirements that:

 

  Ÿ  

a majority of our Board of Directors consists of independent directors;

 

  Ÿ  

we have a nominating and governance committee that is composed entirely of independent directors, with a written charter addressing the committee’s purpose and responsibilities;

 

  Ÿ  

we have a compensation committee that is composed entirely of independent directors, with a written charter addressing the committee’s purpose and responsibilities; and

 

  Ÿ  

we conduct an annual performance evaluation of the nominating and governance committee and compensation committee.

We intend to rely on some or all of these exemptions, and, as a result, you will not have the same protection afforded to shareholders of companies that are subject to all of the NYSE corporate governance requirements.

Risks Related to Our Organizational Structure, this Offering and

an Investment in our Class A Common Stock

Our only material asset after completion of this offering will be our interest in COS LLC, and we are accordingly dependent upon distributions from COS LLC to pay taxes and other expenses.

We and COS LLC are holding companies and we conduct our business through and are dependent upon COO and its subsidiaries, which own all of our operating assets and conduct all of our operations. We and COS LLC have no independent means of generating revenue and are dependent upon COO to do so. COO’s ability to generate revenue and cash flow is subject to the other risks described herein. Additionally, its ability to distribute cash to us is restricted by the indenture governing our 2019 Senior Notes and the terms of our revolving bank credit facility, as well as applicable laws and regulations. While we intend to cause COS LLC to distribute cash to us and Chesapeake in an amount at least equal to that necessary to cover tax liabilities, if any, with respect to the earnings of COS LLC, its ability to do so will be subject to the foregoing risks and limitations.

We will be required to pay Chesapeake for certain tax benefits we may claim arising in connection with prior acquisitions by us, this offering and future exchanges of Class B units, and the amounts we pay could be significant.

We will enter into a tax receivable agreement with Chesapeake that will provide for the payment from us to Chesapeake of 85% of the tax benefits, if any, that we realize or are deemed to realize as a result of (a) the tax basis increases in the assets of COS LLC that arose from certain recent acquisitions by us, (b) any tax basis increase resulting from COS LLC’s distribution of offering proceeds to Chesapeake, (c) the tax basis increases resulting from exchanges by Chesapeake of its Class B units of COS LLC for shares of our Class A common stock, (d) additional deductions allocated to us pursuant to Section 704(c) of the Code to reflect the difference between the fair market value and the adjusted tax basis of COS LLC’s assets as of the date of this offering and (e) imputed interest deemed to be paid by us as a result of, and additional tax basis arising from, payments under the tax receivable agreement. See “Certain Relationships and Related Party Transactions—Tax Receivable Agreement.”

 

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We expect that the payments that we may make under the tax receivable agreement will be substantial. Assuming no material changes in the relevant tax law, and that we earn sufficient taxable income to realize all tax benefits that are subject to the tax receivable agreement, we expect that future payments under the tax receivable agreement relating to (a) increases in tax basis in the assets that arose from certain recent acquisitions, (b) additional deductions allocated to us to reflect the difference between the fair market value and the adjusted tax basis of COS LLC’s assets as of the date of this offering, (c) any tax basis increase resulting from COS LLC’s distribution to Chesapeake of a portion of the net proceeds of this offering, (d) deductions for interest deemed paid by us and (e) tax basis arising from payments under the tax receivable agreement will aggregate $        (or $        if the underwriters exercise their option to purchase additional shares of Class A common stock in full) and will range over the next 15 years from approximately $        million to $        million per year (or approximately $        million to $        million per year if the underwriters exercise their option to purchase additional shares of Class A common stock in full) and then decline thereafter. Future payments to Chesapeake in respect of subsequent exchanges of Class B units of COS LLC for shares of our Class A common stock would be in addition to these amounts and are expected to be substantial as well. The foregoing numbers are merely estimates and the actual payments could differ materially. It is possible that future transactions or events could increase or decrease the actual tax benefits realized and the corresponding tax receivable agreement payments. There may be a material negative effect on our liquidity if, as a result of timing discrepancies or otherwise, the payments under the tax receivable agreement exceed the actual benefits we realize in respect of the tax attributes subject to the tax receivable agreement, and/or distributions to us by COS LLC are not sufficient to permit us to make payments under the tax receivable agreement after we have paid our taxes and other obligations. The payments under the tax receivable agreement are not conditioned upon Chesapeake’s continued ownership of us.

In certain cases, payments to Chesapeake under the tax receivable agreement may be accelerated and/or significantly exceed the actual benefits we realize in respect of the tax attributes subject to the tax receivable agreement.

The tax receivable agreement will provide that upon certain mergers, asset sales, other forms of business combinations or other changes of control, or if, at any time, we elect an early termination of the tax receivable agreement, we would be obligated to make payments under that agreement based on certain assumptions, including that we would have sufficient taxable income to fully utilize the deductions arising from the increased tax deductions and tax basis and other benefits related to entering into the tax receivable agreement. As a result, (a) we could be required to make payments under the tax receivable agreement that are greater than the specified percentage of the actual benefits we realize in respect of the tax attributes subject to the tax receivable agreement and (b) if we elect to terminate the tax receivable agreement early, we would be required to make an immediate payment equal to the present value of the anticipated future tax benefits, which upfront payment may be made years in advance of the actual realization, if any, of such future benefits. Upon an exchange of Class B units of COS LLC for our Class A common stock following a change of control, any additional increase in tax deductions, tax basis and other benefits in excess of the amounts assumed at the change of control will also result in payments under the tax receivable agreement. In these situations, our obligations under the tax receivable agreement could have a substantial negative impact on our liquidity. We may not be able to finance our obligations under the tax receivable agreement and the terms of our existing indebtedness may limit our subsidiaries’ ability to make distributions to us to pay these obligations.

The tax receivable agreement will provide for the payment from us to Chesapeake of 85% of the tax benefits, if any, that we are deemed to realize as a result of, among other things, the increases in tax basis in the assets of COS LLC that arose from certain recent acquisitions by Chesapeake. In order to calculate the amount we would have been required to pay absent the increase in tax basis as result

 

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of each acquisition, we will need to determine the tax basis in the assets of COS LLC in effect prior to such acquisition. This determination will be made in our sole judgment based on information received in connection with such acquisition and consistent with COS LLC’s current tax reporting. This information will not be subject to verification by any third party, and there thus can be no assurance that the historic tax basis as determined by us will be accurate and that payments by us under the tax receivable agreement will not exceed 85% of the cash savings that we actually realize.

Payments under the tax receivable agreement will be based on the tax reporting positions that we determine in accordance with the tax receivable agreement. We will not be reimbursed for any payments previously made under the tax receivable agreement; however, such payments will be determined based upon the cumulative net tax benefit to us, which would reflect any reduction in tax benefit for any prior period as a result of an audit. As a result, in certain circumstances, payments could be made under the tax receivable agreement in excess of the benefits that we actually realize.

Additionally, were the Internal Revenue Service (the “IRS”) to successfully challenge the tax basis increases, we would not be reimbursed for any payments made under the tax receivable agreement. As a result, in certain circumstances, we could make payments under the tax receivable agreement in excess of our cash tax savings.

If we are deemed to be an investment company, we may be required to institute burdensome compliance requirements and our activities may be restricted, which may make it difficult for us to complete strategic acquisitions or effect combinations.

If we are deemed an investment company under the Investment Company Act of 1940 (the “Investment Company Act”), our business would be subject to applicable restrictions under that Act, which could make it impracticable for us to continue our business as contemplated.

We believe our company is not an investment company under Section 3(b)(1) of the Investment Company Act because we are primarily engaged in a non-investment company business. We intend to conduct our operations so that we will not be deemed an investment company. However, if we were to be deemed an investment company, restrictions imposed by the Investment Company Act, including limitations on our capital structure and our ability to transact with affiliates, could make it impractical for us to continue our business as contemplated.

The initial public offering price of our Class A common stock may not be indicative of the market price of our Class A common stock after this offering. In addition, an active liquid trading market for our Class A common stock may not develop and our stock price may be volatile.

Prior to this offering, our Class A common stock has not traded on any market. An active and liquid trading market for our Class A common stock may not develop or be maintained after this offering. Liquid and active trading markets usually result in less price volatility and more efficiency in carrying out investors’ purchase and sale orders. The market price of our Class A common stock could vary significantly as a result of a number of factors, some of which are beyond our control. In the event of a drop in the market price of our Class A common stock, you could lose a substantial part or all of your investment in our Class A common stock. The initial public offering price will be negotiated between us and representatives of the underwriters, based on numerous factors that we discuss in the “Underwriting” section of this prospectus, and may not be indicative of the market price of our Class A common stock after this offering. Consequently, you may not be able to sell shares of our Class A common stock at prices equal to or greater than the price paid by you in the offering.

 

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The following factors, among others, could affect our stock price:

 

  Ÿ  

our operating and financial performance;

 

  Ÿ  

quarterly variations in the rate of growth of our financial indicators, such as net income per share, net income and revenues;

 

  Ÿ  

changes in revenue or earnings estimates or publication of reports by equity research analysts;

 

  Ÿ  

speculation in the press or investment community;

 

  Ÿ  

sales of our Class A common stock by us or Chesapeake following an exchange of its Class B units of COS LLC for our Class A common stock, or the perception that such sales may occur;

 

  Ÿ  

general market conditions, including fluctuations in actual and anticipated future commodity prices; and

 

  Ÿ  

domestic and international economic, legal and regulatory factors unrelated to our performance.

The stock markets in general have experienced extreme volatility that has often been unrelated to the operating performance of particular companies. These broad market fluctuations may adversely affect the trading price of our Class A common stock.

Purchasers of Class A common stock in this offering will experience immediate and substantial dilution.

Based on an assumed initial public offering price of $        per share (the midpoint of the price range set forth on the cover page of this prospectus), purchasers of our Class A common stock in this offering will experience an immediate and substantial dilution of $        per share in the pro forma as adjusted net tangible book value per share of our Class A common stock from the initial public offering price. Our pro forma as adjusted net tangible book value as of                     , 2012 after giving effect to this offering would be $        per share. See “Dilution” for a complete description of the calculation of net tangible book value.

The requirements of being a public company, including compliance with the reporting requirements of the Securities Exchange Act of 1934, as amended, which we refer to as the Exchange Act, and the requirements of the Sarbanes-Oxley Act, may strain our resources, increase our costs and distract management. We may be unable to comply with these requirements in a timely or cost-effective manner.

As a public company with listed equity securities, we will have to comply with numerous laws, regulations and requirements, certain corporate governance provisions of the Sarbanes-Oxley Act of 2002, the Dodd-Frank Wall Street Reform and Consumer Protection Act, related regulations of the SEC and the requirements of the NYSE, with which we are not required to comply as a wholly owned subsidiary of Chesapeake. Complying with these statutes, regulations and requirements will occupy a significant amount of time of our Board of Directors and management and will significantly increase our costs and expenses. We will need to:

 

  Ÿ  

institute a more comprehensive compliance function;

 

  Ÿ  

expand, evaluate and maintain our system of internal controls over financial reporting in compliance with the requirements of Section 404 of the Sarbanes-Oxley Act of 2002 and the related rules and regulations of the SEC and the Public Company Accounting Oversight Board (the “PCAOB”);

 

  Ÿ  

establish new internal policies, such as those relating to disclosure controls and procedures and insider trading;

 

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  Ÿ  

comply with corporate governance and other rules promulgated by the NYSE;

 

  Ÿ  

prepare and file annual, quarterly and other periodic public reports in compliance with the federal securities laws;

 

  Ÿ  

prepare proxy statements and solicit proxies in connection with annual meetings of our shareholders;

 

  Ÿ  

involve and retain to a greater degree outside counsel and accountants in the above activities; and

 

  Ÿ  

establish an investor relations function.

In addition, we also expect that being a public company subject to these rules and regulations will require us to accept less director and officer liability insurance coverage than we desire or to incur substantial costs to obtain such coverage. These factors could also make it more difficult for us to attract and retain qualified members of our Board of Directors, particularly to serve on our Audit Committee, and qualified executive officers.

We may be unsuccessful in implementing required internal controls over financial reporting.

We are not currently required to comply with the SEC’s rules implementing Section 404 of the Sarbanes-Oxley Act of 2002, and are therefore not required to make a formal assessment of the effectiveness of our internal control over financial reporting for that purpose. Upon becoming a public company, we will be required to comply with the SEC’s rules implementing Section 302 of the Sarbanes-Oxley Act of 2002, which will require our management to certify financial and other information in our quarterly and annual reports and provide an annual management report on the effectiveness of our internal control over financial reporting. We will not be required to make our first assessment of our internal control over financial reporting until the year following our first annual report required to be filed with the SEC. To comply with the requirements of being a public company, we will need to upgrade our systems, including information technology, implement additional financial and management controls, reporting systems and procedures and hire additional accounting, finance and legal staff.

We are in the process of evaluating our internal control systems to allow management to report on, and our independent auditors to assess, our internal controls over financial reporting. We will be performing the system and process evaluation and testing (and any necessary remediation) required to comply with the management certification and auditor attestation requirements of Section 404 of the Sarbanes-Oxley Act. Furthermore, upon completion of this process, we may identify control deficiencies of varying degrees of severity under applicable SEC and PCAOB rules and regulations that remain unremediated. As a public company, we will be required to report, among other things, control deficiencies that constitute a “material weakness” or changes in internal controls that materially affect, or are reasonably likely to materially affect, internal controls over financial reporting. The PCAOB has defined a material weakness as a deficiency, or combination of deficiencies, in internal control over financial reporting such that there is a reasonable possibility that a material misstatement of the company’s annual or interim financial statements will not be prevented, or detected and subsequently corrected, on a timely basis.

Our efforts to develop and maintain effective internal controls may not be successful, and we may be unable to maintain effective controls over our financial processes and reporting in the future and comply with the certification and reporting obligations under Sections 302 and 404 of the Sarbanes-Oxley Act. Any failure to remediate future deficiencies and to develop or maintain effective controls, or any difficulties encountered in our implementation or improvement of our internal controls over financial reporting could result in material misstatements that are not prevented or detected on a timely basis,

 

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which could potentially subject us to sanctions or investigations by the SEC, the NYSE or other regulatory authorities. Ineffective internal controls could also cause investors to lose confidence in our reported financial information.

We do not intend to pay dividends on our Class A common stock in the immediate future, and our ability to pay dividends in the future may be restricted by the terms of the revolving bank credit facility of COO and the indenture governing the 2019 Senior Notes.

We do not plan to declare dividends on shares of our Class A common stock in the immediate future. Additionally, all of our operations are conducted through COO and COO is currently limited in its ability to make cash distributions to us pursuant to the terms of the indenture governing the 2019 Senior Notes and the revolving bank credit facility, which in turn limits our ability to make cash distributions to shareholders. Consequently, your only opportunity to achieve a return on your investment in us in the immediate future will be if the market price of our Class A common stock appreciates, which may not occur, and you sell your shares at a profit. There is no guarantee that the price of our Class A common stock that will prevail in the market after this offering will ever exceed the price that you pay. See “Dividend Policy.”

Our share price may decline because of Chesapeake’s ability to sell our Class A common stock following an exchange.

Sales of substantial amounts of our Class A common stock after this offering, or the possibility of those sales, including sales by Chesapeake of our Class A common stock received upon exchange of its Class B units of COS LLC, could adversely affect the market price of our Class A common stock and impede our ability to raise capital through the issuance of equity securities. See “Shares Eligible for Future Sale” for a discussion of possible future sales of our Class A common stock.

The shares of our Class A common stock sold in this offering will be freely tradable without restriction in the U.S., by persons other than our affiliates. In connection with this offering, we and Chesapeake have agreed with the underwriters, subject to certain exceptions, not to sell, dispose of or hedge any of our Class A common stock or securities convertible into or exchangeable for shares of Class A common stock until 180 days after the date of this prospectus. See “Underwriting.” Subject to applicable securities laws, after the expiration of the 180-day lock-up period, Chesapeake may sell shares of our Class A common stock through a public offering, sales under Rule 144, or another transaction. Additionally, after the expiration of the 180-day lock-up period, Chesapeake will have the ability to cause us to register the resale of shares of our Class A common stock that may be issued to Chesapeake upon exchange of its Class B units of COS LLC. See “Certain Relationships and Related Party Transactions—Registration Rights Agreement.”

Future sales of our Class A common stock in the public market could lower our stock price, and any additional capital raised by us through the sale of equity or convertible securities may dilute your ownership in us.

We may sell additional shares of Class A common stock in subsequent public offerings and may also issue securities convertible into our Class A common stock. After the completion of this offering, we will have                     outstanding shares of Class A common stock. This number includes             shares that we are selling in this offering (assuming no exercise of the underwriters’ option to purchase additional shares of Class A common stock), which may be resold immediately in the public market. Following the completion of this offering, Class B units of COS LLC owned by Chesapeake will be freely exchangeable into             shares of our Class A common stock, which would represent approximately                     of our total outstanding shares of Class A common stock on an as-converted basis, all of which are restricted from immediate resale under the federal securities laws and are

 

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subject to the lock-up agreement between Chesapeake and the underwriters described in “Underwriting,” but may be sold into the market in the future.

We cannot predict the size of future issuances of our Class A common stock or the effect, if any, that future issuances and sales of shares of our Class A common stock will have on the market price of our Class A common stock. Sales of substantial amounts of our Class A common stock (including shares issued in connection with an acquisition), or the perception that such sales could occur, may adversely affect prevailing market prices of our Class A common stock.

Our certificate of incorporation and bylaws, as well as Oklahoma law, will contain provisions that could discourage acquisition bids or merger proposals, which may adversely affect the market price of our common stock.

Some provisions in our certificate of incorporation and bylaws, as well as Oklahoma statutes, may have the effect of delaying, deferring or preventing a change of control. These provisions, including those providing for a classified Board of Directors, the possible issuance of shares of our preferred stock and the right of the Board of Directors to amend the bylaws, may make it more difficult for other persons, without the approval of our Board of Directors, to make a tender offer or otherwise acquire a substantial number of shares of our common stock or to launch other takeover attempts that a shareholder might consider to be in his or her best interest. These provisions could limit the price that some investors might be willing to pay in the future for shares of our common stock. See “Description of Capital Stock—Anti-Takeover Effects of Provisions of Our Certificate of Incorporation, Our Bylaws and Oklahoma Law.”

 

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CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS

Certain statements contained in this prospectus constitute forward-looking statements. These statements relate to future events or our future performance. All statements other than statements of historical fact may be forward-looking statements. Forward-looking statements are often, but not always, identified by the use of words such as “seek,” “anticipate,” “plan,” “continue,” “estimate,” “expect,” “may,” “will,” “project,” “predict,” “potential,” “targeting,” “intend,” “could,” “might,” “should,” “believe” and similar expressions. These statements involve known and unknown risks, uncertainties and other facts that may cause actual results or events to differ materially from those anticipated in such forward-looking statements. We believe the expectations reflected in these forward-looking statements are reasonable but we cannot assure you that these expectations will prove to be correct. You should not place undue reliance on forward-looking statements included in this prospectus. We do not intend, and do not assume any obligation, to update any forward-looking statements.

Our actual results could differ materially from those anticipated in these forward-looking statements as a result of many factors, including the following factors and the factors discussed in “Risk Factors” and elsewhere in this prospectus:

 

  Ÿ  

dependence on Chesapeake for a substantial majority of our revenues;

 

  Ÿ  

Chesapeake’s expenditures for oilfield services;

 

  Ÿ  

the limitations that Chesapeake’s and our own level of indebtedness may have on our financial flexibility;

 

  Ÿ  

the cyclical nature of the oil and natural gas industry;

 

  Ÿ  

changes in the supply of drilling rigs, hydraulic fracturing fleets and other equipment;

 

  Ÿ  

the availability of capital resources to fund capital expenditures and other contractual obligations, and our ability to access those resources through the debt or equity capital markets;

 

  Ÿ  

hazards and operational risks that may not be fully covered by insurance;

 

  Ÿ  

increased labor costs or the unavailability of skilled workers;

 

  Ÿ  

competitive conditions; and

 

  Ÿ  

legislative or regulatory changes, including changes in environmental regulations, environmental risks and liability under federal and state environmental laws and regulations.

The foregoing factors should not be construed as exhaustive and should be read together with the other cautionary statements included in this prospectus, including the information presented under the heading “Risk Factors.” If one or more events related to these or other risks and uncertainties materialize, or if our underlying assumptions prove to be incorrect, our actual results may differ materially from what we anticipate. Except as may be required by law, we do not intend, and do not assume any obligation, to update any forward-looking statements.

 

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ORGANIZATIONAL STRUCTURE

COS Holdings, L.L.C.

On October 25, 2011, Chesapeake completed the process of reorganizing its oilfield services subsidiaries and operations as subsidiaries of COS LLC and commenced providing all of its oilfield services through COS LLC. In connection with this reorganization, certain property, equipment and lease rights as to non-owned drilling rigs used in COS LLC’s operations were transferred to Chesapeake and agreements were entered into between Chesapeake, COS LLC and COO in order to provide COS LLC with continuing access to, and rights to use, such assets and to receive certain services. See “Certain Relationships and Related Party Transactions—Prior Transactions with Chesapeake.”

Chesapeake Oilfield Services, Inc.

We were incorporated in Oklahoma on April 10, 2012 and have not engaged in any business or other activities except in connection with our formation and the offering transactions described in this prospectus. Our business is presently conducted through COS LLC, which has been a wholly owned subsidiary of Chesapeake prior to this offering. Following this offering, our only material asset will be our ownership of Class A units of COS LLC and our only business will be acting as the sole managing member of COS LLC.

Offering Transactions

Concurrently with the closing of this offering, our certificate of formation will be amended and restated to authorize two classes of capital stock, Class A common stock and Class B common stock. Each share of our Class A common stock will entitle its holder to one vote on all matters to be voted on by shareholders generally. Each share of our Class B common stock will entitle its holder to          votes on all matters to be voted on by shareholders generally until the first time that the number of shares of our Class B common stock outstanding constitutes less than         % of the number of all shares of our common stock outstanding. Holders of our Class A common stock and Class B common stock will vote together as a single class on all matters presented to shareholders for their vote or approval, except as otherwise required by law. See “Description of Capital Stock.” In addition, the operating agreement of COS LLC will be amended and restated to appoint us as the sole managing member of COS LLC and to authorize two classes of units, Class A units and Class B units.

At the closing of this offering, we will issue                 shares of Class A common stock to the purchasers in this offering in exchange for net proceeds of approximately $        million. We will use the net proceeds from this offering to acquire newly issued Class A units from COS LLC, representing     % of COS LLC’s outstanding membership units. Chesapeake’s existing membership units in COS LLC will be reclassified as “Class B units” and will represent     % of COS LLC’s outstanding membership units following this offering. In addition, we will issue to Chesapeake a number of shares of our Class B common stock equal to the number of Class B units of COS LLC held by Chesapeake immediately following this offering in exchange for the payment by Chesapeake of the aggregate par value of such shares.

If the underwriters exercise their option to purchase additional shares of Class A common stock in full in connection with this offering, we intend to use the additional net proceeds to acquire additional Class A units from COS LLC and, as a consequence thereof, we would own Class A units representing     % of COS LLC’s total outstanding membership units and Chesapeake would own Class B units representing     % of COS LLC’s total outstanding membership units.

At any time following this offering, Chesapeake may (subject to the terms of the amended and restated operating agreement of COS LLC) exchange its Class B units in COS LLC for shares of our

 

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Class A common stock on a one-for-one basis. See “Certain Relationships and Related Party Transactions—Amended and Restated Operating Agreement of COS LLC—Exchange Rights.”

As a result of recent acquisitions by Chesapeake, the consummation of the offering transactions and future exchanges of Class B units of COS LLC for shares of our Class A common stock by Chesapeake, there will be an increase in our share of the tax basis of the assets held directly and indirectly by COS LLC and increased tax deductions allocable to us. These increases in tax basis and increase in available tax deductions may also decrease our allocable share of gains (or increase allocable losses) on future dispositions of certain assets to the extent tax basis is allocated to those assets. As a result, we may incur less taxes than if such basis and additional deductions were not available. We will enter into a tax receivable agreement with Chesapeake that will provide for the payment by us to Chesapeake of 85% of the amount of the benefits, if any, that we realize or are deemed to realize as a result of (a) the tax basis increases in the assets of COS LLC that arose from certain recent acquisitions by us, (b) any tax basis increase resulting from COS LLC’s distribution of offering proceeds to Chesapeake, (c) the tax basis increases resulting from exchanges by Chesapeake of its Class B units of COS LLC for shares of our Class A common stock, (d) additional deductions allocated to us pursuant to Section 704(c) of the Code to reflect the difference between the fair market value and the adjusted tax basis of COS LLC’s assets as of the date of this offering and (e) imputed interest deemed to be paid by us as a result of, and additional tax basis arising from, payments under the tax receivable agreement. We estimate that the incremental tax basis of the assets of COS LLC that will be attributable to us at the time of this offering will be approximately $        million. See “Certain Relationships and Related Party Transactions—Tax Receivable Agreement.”

In connection with our acquisition of Class A units of COS LLC, we will be appointed as the sole managing member of COS LLC. Accordingly, although we will initially have a minority economic interest in COS LLC, we will have 100% of the voting power and will control the management of COS LLC.

As a result of the transactions described above:

 

  Ÿ  

the purchasers in this offering will collectively own                 shares of our Class A common (or                 shares of Class A common stock if the underwriters exercise their option to purchase additional shares of Class A common stock in full);

 

  Ÿ  

We will hold                     Class A units of COS LLC (or                     Class A units if the underwriters exercise their option to purchase additional shares of Class A common stock in full);

 

  Ÿ  

We will be appointed as the sole managing member of COS LLC;

 

  Ÿ  

the purchasers in this offering will collectively have     % voting power in us and, through our ownership of Class A units of COS LLC, a     % economic interest in COS LLC (or     % voting power in us and a     % economic interest in COS LLC if the underwriters exercise their option to purchase additional shares of Class A common stock in full);

 

  Ÿ  

Chesapeake will hold                 shares of our Class B common stock (or                 shares of Class B common stock if the underwriters exercise their option to purchase additional shares of Class A common stock in full) and Class B units of COS LLC (or                     Class B units if the underwriters exercise their option to purchase additional shares of Class A common stock in full); and

 

  Ÿ  

Chesapeake, through its ownership of our Class B common stock, will have     % of the voting power in us and, through its ownership of Class B units of COS LLC, a     % economic interest in COS LLC (or     % voting power in us and a     % economic interest in COS LLC if the underwriters exercise their option to purchase additional shares of Class A common stock in full).

 

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Our post-offering organizational structure will allow Chesapeake to retain its equity ownership in COS LLC, an entity that is classified as a partnership for U.S. federal income tax purposes, in the form of Class B units. Investors in this offering will, by contrast, hold their equity ownership in us in the form of our Class A common stock. We are an Oklahoma corporation that is a domestic corporation for U.S. federal income tax purposes, and we do not believe that our organizational structure gives rise to any significant benefit or detriment to our business or operations.

Holding Company Structure

We will be a holding company following this offering and our sole material asset will be the Class A units of COS LLC that we own. As the sole managing member of COS LLC, we will control all of the business and affairs of COS LLC and its subsidiaries. Initially, Chesapeake, as the holder of all of our Class B common stock, will have     % of the combined voting power of our outstanding common stock (or     % if the underwriters exercise their option to purchase additional shares of Class A common stock in full). Therefore, upon the closing of this offering and for the foreseeable future thereafter, Chesapeake will be able to exercise control over all matters requiring the approval of our shareholders, including the election of directors and the approval of significant corporate transactions.

As COS LLC’s sole managing member, we will consolidate the financial results of COS LLC and its subsidiaries into our financial statements. Chesapeake’s ownership of Class B units of COS LLC will be accounted for as a minority interest in our consolidated financial statements after this offering.

Net profits and net losses and distributions by COS LLC will be allocated and made to us and Chesapeake pro rata in accordance with our and Chesapeake’s respective ownership of COS LLC. Accordingly, net profits and net losses of COS LLC will initially be allocated, and distributions will be made, approximately     % to us and approximately     % to Chesapeake (or     % and     %, respectively, if the underwriters exercise their option to purchase additional shares of Class A common stock in full).

Subject to the availability of net cash flow at the COS LLC level, we intend to cause COS LLC to distribute to us and Chesapeake cash payments for the purpose of funding tax obligations in respect of taxable income and net capital gain allocated to us and Chesapeake, respectively, as members of COS LLC as well as additional payments if any, due us or Chesapeake under the tax receivable agreement.

Assuming COS LLC makes distributions to its members in any given year, the determination to pay dividends, if any, to our Class A shareholders will be made by our Board of Directors. Because our Board of Directors may or may not determine to pay dividends to Class A shareholders, Class A shareholders may not necessarily receive dividend distributions relating to our pro rata share of the income earned by COS LLC, even if COS LLC makes such distributions to us.

In connection with an exchange by Chesapeake of its Class B units of COS LLC for shares of our Class A common stock, we will automatically redeem and cancel a corresponding number of shares of our Class B common stock. Accordingly, Chesapeake’s exchange of Class B units of COS LLC for shares of our Class A common stock will decrease Chesapeake’s share of the combined voting power of our outstanding common stock.

 

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USE OF PROCEEDS

We will receive net proceeds of approximately $         from our sale of shares of our Class A common stock in this offering, assuming an initial public offering price of $         per share (the midpoint of the price range set forth on the cover page of this prospectus) and after deducting estimated expenses and underwriting discounts of approximately $         million. If the option to purchase additional shares of Class A common stock that we have granted to the underwriters is exercised in full, we estimate that the net proceeds to us will be approximately $         million.

We intend to use the net proceeds from this offering to acquire newly issued Class A units from COS LLC. COS LLC will use $         million of the net proceeds it receives to make a cash capital contribution to COO, which will use such cash to repay outstanding borrowings under its revolving bank credit facility and for general corporate purposes. COO’s credit facility matures on November 3, 2016 and, as of April 10, 2012, the weighted average interest rate applicable to borrowings under the credit facility was 2.79%. Borrowings under the revolving bank credit facility in the past year were incurred for capital expenditures on equipment and other general corporate purposes.

COS LLC will use $         million of the net proceeds to repay the balance outstanding under an intercompany promissory note with Chesapeake. The promissory note matures on October 1, 2016, but demand for payment of the principal amount plus accrued and unpaid interest may be made by Chesapeake at any time. Amounts outstanding under the note bear interest at 6.875% per annum. Borrowings under the promissory note in the past year were incurred for capital expenditures on equipment and other general corporate purposes.

COS LLC will distribute the remaining $         million of the net proceeds it receives to Chesapeake Operating, Inc., a wholly owned subsidiary of Chesapeake.

The table below sets forth the sources and uses of the net proceeds of this offering by us and COS LLC (based on the foregoing assumptions):

 

Sources:

  

Proceeds to COS Inc. from sale of Class A common stock in this offering

   $                

Underwriting discounts and commissions

  

Offering expenses

  
  

 

 

 

Total net proceeds used to purchase Class A units of COS LLC

   $     
  

 

 

 

Uses:

  

Capital contribution to COO

   $     

Repayment of intercompany promissory note payable to Chesapeake

  

Distribution to Chesapeake

  
  

 

 

 

Total net proceeds used to purchase Class A units of COS LLC

   $     
  

 

 

 

We intend to use any additional proceeds we receive if the underwriters exercise their option to purchase additional shares of Class A common stock to acquire additional Class A units from COS LLC and COS LLC will distribute any such proceeds to Chesapeake.

Chesapeake has advised us that it intends to use the net proceeds distributed to it by COS LLC to repay borrowings under its corporate revolving bank credit facility, under which it may re-borrow from time to time and does so for general corporate purposes, including land, drilling and other costs.

Affiliates of Goldman, Sachs & Co. and Merrill Lynch, Pierce, Fenner & Smith Incorporated are lenders under our revolving bank credit facility and under Chesapeake’s corporate revolving bank credit facility and will, thus, receive a portion of the net proceeds from this offering through the repayment of borrowings outstanding under such credit facilities.

 

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Each $1.00 increase (decrease) in the public offering price would increase (decrease) our net proceeds by approximately $         million, assuming that the number of shares offered by us, as set forth on the cover page of this prospectus, remains the same and after deducting the underwriting discounts and commissions and estimated offering expenses payable by us.

DIVIDEND POLICY

We currently intend to retain future earnings, if any, for use in the operation and expansion of our business and, therefore, do not anticipate paying any cash dividends on our Class A common stock in the immediate future following this offering. However, our Board of Directors, in its discretion, may authorize the payment of dividends in the future. Any decision to pay future dividends will depend upon various factors, including our results of operations, financial condition, capital requirements and investment opportunities. In addition, all of our operations are conducted through COO and COO’s revolving bank credit facility and its indenture governing the 2019 Senior Notes contain covenants that restrict its ability to make distributions to us, which will, in turn, restrict our ability to make any cash distributions to our shareholders. Holders of our Class B common stock will not have the right to receive regular dividends.

 

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CAPITALIZATION

The following table sets forth the capitalization of COS LLC as of December 31, 2011:

 

  Ÿ  

on an actual basis; and

 

  Ÿ  

on an as adjusted basis to give effect to:

 

  Ÿ  

the transactions described under “Organizational Structure,” and

 

  Ÿ  

the closing of this offering and the application of the estimated net proceeds as described in “Use of Proceeds.”

We derived this table from, and it should be read in conjunction with and is qualified in its entirety by reference to, the consolidated historical financial statements and unaudited pro forma financial data and the accompanying notes included elsewhere in this prospectus. You should also read this table in conjunction with “Management’s Discussion and Analysis of Financial Condition and Results of Operations.”

 

     As of December 31, 2011  
     Actual      As Adjusted  
            (Unaudited)  
     (In thousands)  

Cash and cash equivalents

   $ 2,360       $     
  

 

 

    

 

 

 
   $ 2,360       $     

Long-term debt:

     

Affiliate debt

     371,674         —     

Revolving bank credit facility(1)(2)

     29,000         —     

6.625% Senior Notes due 2019(1)

     650,000         650,000   
  

 

 

    

 

 

 

Total long-term debt

     1,050,674      

Total equity

     181,782      
  

 

 

    

 

 

 

Total capitalization

   $ 1,232,456       $     
  

 

 

    

 

 

 

 

(1) Obligations of our indirect wholly owned subsidiary, COO.
(2) As of April 10, 2012, we had borrowings of $215.7 million outstanding under COO’s revolving bank credit facility.

 

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DILUTION

If you invest in our Class A common stock, your interest will be diluted to the extent of the difference between the initial public offering price per share of our Class A common stock and the pro forma as adjusted net tangible book value per share of our Class A common stock after this offering. We calculate net tangible book value per share by dividing the net tangible book value (tangible assets less total liabilities) by the number of outstanding shares of our Class A common stock.

Our pro forma net tangible book value as of December 31, 2011, after giving effect to our reorganization in connection with this offering, was approximately $             million, or $             per share of Class A common stock, based on                 shares of Class A common stock outstanding immediately prior to the closing of this offering and after giving effect to our corporate reorganization. As of December 31, 2011, after giving effect to our reorganization in connection with this offering and the sale of                 shares of Class A common stock by us in this offering at an assumed initial public offering price of $             per share, the deduction of underwriting discounts and commissions and estimated offering expenses payable by us and the assumed exchange by Chesapeake of the Class B units of COS LLC that it will own immediately following this offering for the corresponding number of shares of our Class A common stock, our pro forma as adjusted net tangible book value as of December 31, 2011, would be $            million, or $            per share. This represents an immediate increase in the pro forma net tangible book value of $            per share to Chesapeake and an immediate dilution of $            per share to new investors purchasing shares in this offering. The following table illustrates this per share dilution:

 

Assumed initial public offering price per share

      $                

Pro forma net tangible book value per share as of December 31, 2011 (after giving effect to our corporate reorganization)

   $                   

Increase per share attributable to this offering

     
  

 

 

    

As adjusted pro forma net tangible book value per share (after giving effect to our corporate reorganization and this offering)

     
     

 

 

 

Dilution per share to new investors in this offering

      $     
     

 

 

 

The following table shows, at December 31, 2011, on a pro forma basis as described above, the difference between the number of shares of Class A common stock purchased from us, the total consideration paid to us and the average price paid per share by Chesapeake and by new investors purchasing Class A common stock in this offering:

 

     Shares Purchased     Total Consideration     Average
Price

per Share
 
     Number    Percent     Amount      Percent    

Chesapeake

               $                             $                

New investors

                          
  

 

  

 

 

   

 

 

    

 

 

   

 

 

 

Total

        100   $           100   $     
  

 

  

 

 

   

 

 

    

 

 

   

 

 

 

Assuming the underwriters’ option to purchase additional shares of Class A common stock is exercised in full, sales by us in this offering will reduce the percentage of shares held by Chesapeake to % and will increase the number of shares held by new investors to                     , or     %. This information is based on shares outstanding as of December 31, 2011. No material change has occurred to our equity capitalization since December 31, 2011.

Each $1.00 increase (decrease) in the assumed public offering price per share of our Class A common stock would increase (decrease) the pro forma deficit in net tangible book value by $             per share (assuming no exercise of the underwriters’ option to purchase additional shares) and the dilution to investors in this offering by $             per share, assuming the number of shares offered by us, as set forth on the cover page of this prospectus, remains the same.

 

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SELECTED HISTORICAL AND PRO FORMA FINANCIAL DATA

The following tables set forth selected historical and unaudited pro forma financial data of COS LLC and its predecessors. The selected financial data for each of the years ended December 31, 2009, 2010 and 2011 are derived from the audited consolidated financial statements included elsewhere in this prospectus. The selected financial data for each of the years ended December 31, 2007 and 2008 are derived from the unaudited consolidated financial statements not included in this prospectus. Our historical consolidated financial statements for periods and as of dates prior to our October 25, 2011 reorganization were prepared on a “carve-out” basis from Chesapeake and are intended to represent the financial results of Chesapeake’s oilfield service operations for those periods. The selected historical financial data are not necessarily indicative of results to be expected in future periods. Our selected historical financial data should be read together with the historical consolidated financial statements and related notes thereto and “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” each included elsewhere in this prospectus.

The selected unaudited pro forma financial data as of December 31, 2011 and for the year ended December 31, 2011 is derived from the audited consolidated financial statements included elsewhere in this prospectus and includes pro forma adjustments to give effect to certain transactions that occurred during the year ended December 31, 2011 and the transactions associated with our formation and this offering. Our selected unaudited pro forma financial data should be read together with the unaudited pro forma consolidated financial statements and related notes thereto included elsewhere in this prospectus.

The financial statements of COS Inc. have not been presented in this prospectus as it is a newly incorporated entity, has had no business transactions or activities to date and has no (or nominal) assets or liabilities.

 

    Years Ended December 31,  
    COS LLC Historical     Pro Forma
Combined (3)
 
    2007     2008     2009     2010     2011     2011  
    (Unaudited)     (Unaudited)                       (Unaudited)  
    (In thousands)  

Income Statement Data:

           

Revenues, including revenues from affiliates

  $ 503,605      $ 652,828      $ 650,279      $ 815,756      $ 1,303,496      $ 1,366,066   

Operating costs

    315,189        491,373        556,008        666,924        987,032        1,036,399   

Depreciation and amortization

    27,600        38,646        70,429        106,425        171,908        180,236   

General and administrative, including expenses from affiliates

    8,323        13,449        17,735        25,312        37,074        45,902   

Losses (gains) on sales of property and equipment

    204        283        (1,551     (854     (3,571     (3,546

Impairments

    —          277        26,797 (1)      9        2,729        3,408   
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Operating income (loss)

    152,289        108,800        (19,139     17,940        108,324        103,667   
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Interest expense, including expenses from affiliates

    (12,352     (6,161     (23,453     (38,511     (65,072  

Losses from equity investee

    —          —          (164     (2,243     —          —     

Other income (expense)

    72        387        (283     211        (2,464     (1,979
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Total other expense

    (12,280     (5,774     (23,900     (40,543     (67,536  
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Income (loss) before income taxes

    140,009        103,026        (43,039     (22,603     40,788     

Income tax expense (benefit)

    55,524        40,473        (2,656     (3,751     21,030     
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Net income (loss)

  $ 84,485      $ 62,553        (40,383     (18,852     19,758     
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Less: Net Loss Attributable to Noncontrolling Interest

    —          —          —          (639     (154  
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Net Income (Loss) Attributable to COS Holdings, L.L.C.

  $ 84,485      $ 62,553      $ (40,383   $ (18,213   $ 19,912     
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Other Financial Data:

           

Adjusted EBITDA(2)(unaudited)

  $ 180,165      $ 148,393      $ 76,089      $ 121,488      $ 276,926      $     

Capital expenditures (including acquisitions)

  $ 218,610      $ 356,421      $ 325,895      $ 269,769      $ 738,354      $     

 

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     As of December 31, 2011  
     Actual      Pro Forma(4)  
            (Unaudited)  
     (In thousands)  

Balance Sheet Data:

     

Cash

   $ 2,360       $     

Total property and equipment, net

   $ 1,225,580       $ 1,225,580   

Total assets

   $ 1,598,582       $     

Total long-term debt (including current portion)

   $ 1,050,674       $     

Total equity

   $ 181,782       $     

 

(1) We recorded an impairment to goodwill in the amount of $19.8 million and an impairment of long-lived assets in the amount of $7.0 million for the year ended December 31, 2009.
(2) “Adjusted EBITDA” is a non-GAAP financial measure that we define as net income before interest, taxes, depreciation and amortization, as further adjusted to add back gain or loss on sale of property and equipment and impairments. For additional information about this measure and a reconciliation of our Adjusted EBITDA to our net income, the most directly comparable GAAP financial measure, see footnote 2 to the table in “Prospectus Summary—Summary Historical Financial Data.”
(3) Includes pro forma adjustments to give effect to (a) the acquisition of Bronco Drilling Company, Inc. in June 2011, (b) our transfer of certain land and buildings to Chesapeake in October 2011, (c) the issuance by COO of $650.0 million of 6.625% Senior Notes due 2019 in October 2011 and the use of the net proceeds therefrom to repay a portion of an intercompany promissory note owed to Chesapeake, (d) COO’s entry into, and borrowings under, our revolving bank credit facility in November 2011 and (e) our reorganization in connection with, and the closing of, this offering and the application of the estimated net proceeds as described in “Use of Proceeds.”
(4) Includes pro forma adjustments to give effect to our reorganization in connection with, and the closing of, this offering and the application of the estimated net proceeds as described in “Use of Proceeds.”

 

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MANAGEMENT’S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

The following discussion and analysis should be read in conjunction with our historical consolidated financial statements and related notes thereto included elsewhere in this prospectus. This discussion contains forward-looking statements based on our current expectations, assumptions, estimates and projections about our operations, the oilfield services industry and the broader E&P industry. These forward-looking statements involve known and unknown risks, uncertainties and other facts outside of our control that may cause actual results or events to differ materially from those anticipated in such forward-looking statements. Factors that could cause or contribute to such differences include, but are not limited to general economic and competitive conditions, changes in market prices for oil and natural gas, the level of oil and natural gas drilling and corresponding increases or decreases in the demand for our services, the level of capital expenditures by our existing and prospective customers, regulatory changes and other uncertainties, as well as those factors discussed below and elsewhere in this prospectus, particularly in “Cautionary Note Regarding Forward-Looking Statements” and “Risk Factors.”

Executive Summary

We are a diversified oilfield services company that provides a wide range of well site services primarily to Chesapeake, our founder and principal customer, and its partners. Chesapeake is the most active driller of new oil and natural gas wells in the U.S. based on rig count. We focus on providing services to Chesapeake that are strategic to its oil and gas operations, represent historical bottlenecks to those operations or provide relatively high margins to the service provider, including drilling, hydraulic fracturing, oilfield rentals, oilfield trucking and manufacturing of natural gas compressor packages. Our operations are geographically diversified across most major basins in the U.S. Specifically, we provide Chesapeake and its partners with services in the Eagle Ford, Utica, Granite Wash, Cleveland, Tonkawa, Mississippi Lime, Bone Spring, Avalon, Wolfcamp, Wolfberry and Niobrara unconventional liquids plays and the Barnett, Haynesville, Bossier, Marcellus and Pearsall natural gas shale plays.

Our objective is to provide up to two-thirds of Chesapeake’s overall expected needs for our current and future services. This objective, combined with our unique relationship with Chesapeake, makes us fundamentally different than our competitors because it provides us with substantial growth opportunities while at the same time positioning us to maintain our industry-leading asset utilization rates. We believe that our high-growth, high-utilization business model will allow us to continue creating significant shareholder value over time.

Our business has grown rapidly since our first subsidiary was founded in 2001, both organically and through acquisitions, and we are now one of the larger U.S. onshore oilfield service companies. We currently operate 111 land drilling rigs, the fourth largest active rig fleet in the U.S., which represents our largest revenue generating service line today. We also operate (a) four hydraulic fracturing fleets with an aggregate of 140,000 horsepower; (b) one of the largest oilfield rental businesses in the U.S.; (c) one of the largest oilfield trucking fleets in the U.S., currently consisting of 227 rig relocation trucks, 57 cranes and forklifts used in the movement of drilling rigs and other heavy equipment and 157 fluid hauling trucks; and (d) manufacturing capacity for up to 150 compressor units per quarter, or approximately 85,000 horsepower in the aggregate per quarter. We continue to grow our assets rapidly and have ordered 12 drilling rigs that will utilize advanced electronic drilling technology, including 10 of our proprietary, fit-for-purpose PeakeRigs, which are scheduled to be delivered at a rate of approximately one rig per month through May 2013. We have also ordered additional new hydraulic fracturing equipment with an aggregate of 175,000 horsepower,

 

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and we expect to have eight hydraulic fracturing fleets with an aggregate of 315,000 horsepower operating by the end of 2012 and 12 such fleets with an aggregate of 450,000 horsepower operating by the end of 2013. We believe our growth plans will place us among the largest hydraulic fracturing companies in the U.S. by year-end 2014 based on horsepower.

We currently conduct our operations through five operating segments: drilling, hydraulic fracturing, oilfield rentals, oilfield trucking and other operations.

Trends Affecting our Business

Oilfield service companies provide services that are used by E&P companies in connection with the exploration for and the development and production of hydrocarbons. E&P companies operating in the U.S. include independent E&P companies, such as Chesapeake, U.S.-based major integrated oil and gas companies, such as ExxonMobil, ChevronTexaco and ConocoPhillips, and international major integrated oil and gas companies, such as Shell, Total S.A., BP America, CNOOC Limited and Statoil. Demand for domestic onshore oilfield services is a function of the willingness of E&P companies to make operating and capital expenditures to explore for, develop and produce hydrocarbons in the U.S. When oil or natural gas prices increase, E&P companies generally increase their capital expenditures, resulting in greater revenues and profits for oilfield service companies. Likewise, significant decreases in the prices of those commodities typically lead E&P companies to reduce their capital expenditures, which lowers the demand for oilfield services.

Oil and natural gas prices rose to record levels in 2008 and then began to decline in late 2008 in conjunction with the widespread economic recession. While the price of oil rebounded somewhat in 2009 and continued to rise throughout 2010 and 2011, the price of natural gas has continued to fall since 2009 largely due to discoveries of vast new natural gas resources in the U.S. The WTI Cushing spot price of a barrel of crude oil reached an all-time high of $145.29 per barrel in July 2008 and then dropped sharply by the end of the year, falling to as low as $31.41 per barrel on December 22, 2008 before trending upward again by late 2009 and reaching $92.19 in January 2011. During 2011, oil prices generally remained high, averaging $95.05 per barrel through December 31, 2011, due to increased demand, generally flattening international supply and geopolitical tensions. This trend has continued in 2012 with current oil prices above $100 per barrel. On the other hand, from the beginning of 2009 through March 31, 2012, U.S. Henry Hub natural gas prices generally declined from a starting price of $5.40 per mmbtu to an ending price of $2.00 per mmbtu.

 

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The table below sets forth average daily closing prices for the WTI Cushing spot oil price, the average daily closing prices for the Henry Hub price for natural gas and the average Baker Hughes Incorporated U.S. Land Drilling Rig Count since 2001:

 

Period

   Year      Average Daily
Closing Henry
Hub Spot
Natural Gas
Prices ($/mcf)
     Average Daily
Closing WTI
Cushing Spot
Oil Price
($/bbl)
     Average
Baker
Hughes U.S.
Land Drilling
Rig Count
 
                          Oil      Gas  

January 1 – December 31

     2001       $ 3.96       $ 25.94         217         939   

January 1 – December 31

     2002         3.37         26.21         137         691   

January 1 – December 31

     2003         5.49         31.07         157         872   

January 1 – December 31

     2004         5.90         41.54         165         1025   

January 1 – December 31

     2005         8.89         56.65         194         1186   

January 1 – December 31

     2006         6.73         66.09         274         1372   

January 1 – December 31

     2007         6.97         72.23         297         1466   

January 1 – December 31

     2008         8.89         100.63         379         1491   

January 1 – December 31

     2009         3.94         61.47         278         801   

January 1 – December 31

     2010         4.37         79.22         591         943   

January 1 – December 31

     2011         4.00         95.05         984         887   

 

Source: Bloomberg NYMEX Prices and Baker Hughes Incorporated

The number of drilling rigs under contract in the U.S. decreased in 2009 but rebounded in 2010 and has remained high since then relative to historical levels, according to data compiled by Baker Hughes Incorporated. This has remained the case despite a dramatic decrease in the price of natural gas over the same period, suggesting a weakening in the traditional correlation between natural gas prices and U.S. onshore drilling rig counts. We believe this decrease in correlation is attributable to several factors, including the discovery of potentially large oil and liquids-rich unconventional plays onshore in the U.S., the increasing presence in U.S. onshore plays of major U.S. and international integrated E&P companies that are typically less reactive to short-term price fluctuations than independent E&P companies, the presence of term contracts for certain types of oilfield services, the need by operators to commence drilling activities in order to establish production and avoid the expiration of oil and natural gas leases, and the more regimented approach to developing unconventional plays characterized by continuous hydrocarbon accumulations. Additionally, we believe that the weakening correlation between natural gas prices and U.S. onshore rig counts is partially attributable to the prevalence of joint ventures for the development of U.S. unconventional plays, many of which include a drilling “carry” that is paid by the joint venture partner and used by the operator to pay for a portion of the cost of drilling and completing the well. Chesapeake, for example, has entered into several such joint ventures since 2008 with companies such as Total S.A., CNOOC Limited, Statoil, BP America and Plains Exploration & Production Company that have provided more than $9.0 billion of drilling carries to Chesapeake.

 

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LOGO

 

Source: Baker Hughes Incorporated and Bloomberg.

In response to historically low natural gas prices, a number of E&P companies, including Chesapeake, have announced that they are reducing dry natural gas drilling and production and redirecting their activities and capital toward currently more economic liquids-rich plays. Liquids-rich plays are those that are characterized by production of predominantly oil and natural gas liquids such as ethane, propane, butane and iso-butane, which are used as energy sources and manufacturing feedstocks, and the prices of which have historically been highly correlated with oil prices rather than natural gas prices. As a result, we expect the trend toward liquids-focused drilling to continue. The proportion of rigs in the U.S. drilling for liquids versus natural gas has also increased steadily over the past few years and, in April 2011, for the first time since 1993, the number of rigs drilling for liquids plays surpassed the number of rigs drilling for natural gas.

 

LOGO

 

 

Source: Baker Hughes Incorporated

 

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Trends that we believe are affecting, and will continue to affect, our industry include:

Drilling and developing unconventional U.S. hydrocarbon resources.    Due to the maturity of conventional U.S. oil and natural gas reservoirs, the relative abundance of undeveloped unconventional resources and the cost advantage of developing unconventional resources, an increasing proportion of U.S. oil and natural gas production is coming from unconventional resources, which include shale formations. Since the beginning of 2008, producers have spent substantial amounts acquiring properties in unconventional resource plays in the U.S., including approximately $20.0 billion spent by Chesapeake, as advances in horizontal drilling and completion technologies have made the development of many unconventional resources economically attractive.

Horizontal wells are typically drilled in these unconventional formations and tend to involve a higher degree of service intensity associated with their initial drilling and completion, and we believe that these wells will also ultimately require a high degree of service intensity over their lifetime. The U.S. horizontal and directional rig count has risen from 705 (or 42% of the total) at the beginning of 2007 to 1,413 (or 71% of the total) for the week ending March 30, 2012, according to Baker Hughes Incorporated. In addition to an increase in the number of horizontal wells drilled in the U.S., the length of well laterals has increased and the intervals between fracturing stages have decreased over the past several years. The longer laterals and increasing number of fracturing stages have enhanced recoveries and lowered field development costs while causing the number of fracturing stages to grow at a faster rate than the horizontal rig count, creating an increased demand for completion related services.

Increased drilling in liquids-rich formations.    There is increasing horizontal drilling- and completion-related activity in liquids-rich formations such as the Eagle Ford, Utica, Bakken and Niobrara Shales and various other unconventional liquids-rich plays in Texas and Oklahoma, including the Wolfcamp, Bone Spring, Granite Wash, Cleveland and Tonkawa sands and the Mississippi Lime. In January 2012, Chesapeake announced its plan to curtail its dry gas drilling and production activities and redirect capital to its liquids-rich plays. We believe that the oil and natural gas liquids content in these plays significantly enhances the returns for Chesapeake and its partners relative to opportunities in dry gas basins due to the significant disparity between oil and natural gas prices on a British thermal unit (btu) basis. Furthermore, we believe that oil and natural gas liquids prices tend to exhibit less volatility than natural gas prices due to the global nature of the crude oil market and the more localized market for natural gas. We believe that the higher price of liquids relative to natural gas, as well as liquids’ reduced pricing volatility will continue over the near- to medium-term, resulting in increasing demand for services in liquids-rich basins and a reduction in the variability of demand for oilfield services generally.

High asset utilization and tight labor and equipment market.    Many of the unconventional reservoirs in the U.S. are deep, high-pressure and challenging environments, factors that increase the demand for skilled workers and high-quality oilfield services. Equipment manufacturers have had difficulty meeting the demand for services equipment, resulting in high asset utilization levels across the industry. In addition, demand for skilled workers is high and the supply is limited. We believe these trends will continue to keep supply tight in our industry for the foreseeable future.

Complex technologies, techniques and equipment.    The development of unconventional oil and natural gas resources is driving the need for complex new technologies, completion techniques and equipment designed to increase recovery rates, lower production costs and accelerate field development. These needs have spurred the development of more technologically advanced, higher-margin oilfield services that are required to economically produce oil and natural gas from unconventional resources. In addition to rigs with adequate horsepower and top drives, in many cases directional drilling systems are necessary to enable the operator to steer the drill bit into the appropriate section of the reservoir, and advanced technologies, such as the latest hydraulic fracturing, proppant and fluids technologies, are needed for completion of the wells.

 

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Constrained supply of hydraulic fracturing sand.    The sand used as a proppant in hydraulic fracturing operations must meet certain size and other specifications in order to be suitable for hydraulic fracturing purposes. Securing access to hydraulic fracturing sand that conforms to the specifications established by the American Petroleum Institute is increasingly important to suppliers and customers of hydraulic fracturing services. Rising unconventional production in the U.S. will continue to support demand for hydraulic fracturing sand, which is used extensively in domestic unconventional basins. The hydraulic fracturing sand market is driven by the overall demand for oil and natural gas production and, in particular, horizontal drilling of oil and natural gas wells. Accordingly, the demand for hydraulic fracturing sand has grown significantly, paralleling the heightened development activity in unconventional reservoirs. We believe the industry is currently experiencing both high demand and limited supply of hydraulic fracturing sand. As we continue to grow our hydraulic fracturing business, we plan to mitigate this risk by vertically integrating our operations through the integration of sand reserves, sand processing operations and logistics assets such as storage and transload, railcar, trucking and other assets.

How We Generate Our Revenues

We derive substantially all our revenues from the performance of oilfield services for Chesapeake. Chesapeake, as operator of most of the wells that we service, engages us and pays our fees. To the extent that Chesapeake shares the costs of our services with its partners, it seeks separate reimbursement of such shared costs through a joint interest billing. In addition, we perform a small amount of work for other E&P companies. We are a party to a master services agreement with Chesapeake, pursuant to which we provide drilling and other services and supply materials and equipment to Chesapeake. The master services agreement contains general terms and provisions, specifies payment terms, audit rights and insurance requirements and allocates certain operational risks through indemnity and similar provisions. The specific terms of each drilling services request are typically provided pursuant to modified International Association of Drilling Contractors (IADC) drilling contracts on a well-by-well basis. The specific terms of each request for other services are typically set forth in a field ticket or purchase or work order. We generally do not have fixed pricing agreements with Chesapeake and the rates for the services and products we provide are market-based. A brief description of the ways in which we are compensated for the services and products we provide appears below.

Drilling Segment.    Currently, all of our drilling contracts are daywork contracts. A daywork contract generally provides for a basic rate per day when drilling (the dayrate for our providing a rig and crew) and for lower rates when the rig is moving, or when drilling operations are interrupted or restricted by equipment breakdowns, adverse weather conditions or other conditions beyond our control. In addition, daywork contracts may provide for a lump-sum fee for the mobilization and demobilization of the rig, which in most cases approximates our incurred costs. Drilling services can also be provided pursuant to a footage contract in which the drilling contractor is paid on the basis of a rate per foot drilled and a turnkey contract in which the drilling contractor is paid for drilling a well to a specified depth for a fixed price. We expect that all of our future contracts with Chesapeake and third parties will be daywork contracts. Under our services agreement with Chesapeake, Chesapeake has guaranteed that it will operate, on a daywork basis at market-based rates, the lesser of 75 of our drilling rigs or 80% of our operational drilling rig fleet, each referred to as a “committed rig,” subject to reduction for each of our drilling rigs that is operated by a third-party customer. In the event Chesapeake does not meet the drilling commitment, it will be required to pay us a non-utilization fee. For each day that a committed rig is not operated, Chesapeake must pay us our average daily operating cost for our operating drilling rigs for the preceding 30 days, plus 20%, and in no event less than $6,600 per day.

 

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Hydraulic Fracturing Segment.    We are generally compensated based on the number of fracturing stages we complete, and we recognize revenue upon the completion of each fracturing stage. We typically complete one or more fracturing stages per day during the course of a job. A stage is considered complete when the customer requests that pumping discontinue for that stage. Invoices typically include a lump sum equipment charge determined by the rate per stage that each contract specifies and product charges for sand, chemicals and other products actually consumed during the course of providing our services. Under our services agreement with Chesapeake, Chesapeake has guaranteed that each month it will utilize a number of our operational hydraulic fracturing fleets, up to a maximum of 13 fleets, to complete a minimum aggregate number of fracturing stages equal to 25 stages per month at market-based rates times the average number of our operational hydraulic fracturing fleets during such month, each referred to as a “committed stage,” subject to reduction for each stage that we perform for a third-party customer during such month. In the event Chesapeake does not meet the stage commitment, it will be required to pay us a non-utilization fee equal to $40,000 for each committed stage not performed.

Oilfield Rentals Segment.    We rent many types of oilfield equipment to Chesapeake and third parties, including drill pipe, drill collars, tubing, blowout preventers, frac and mud tanks and also provide air drilling services and services associated with the transfer of fresh water to the well site. We price our rentals and services based on the type of equipment being rented and the service job being performed. Substantially all rental revenue we earn is based upon a charge for the actual period of time the rental is provided to our customer on a market-based fixed per-day or per-hour fee.

Oilfield Trucking Segment.    We derive substantially all of our oilfield trucking revenues from rig relocation and logistics services and fluid hauling services. The fees we charge are determined by applying a base rate, which varies depending on the service provided, for the amount of time it took to perform the service.

Other Operations.    We derive substantially all of the revenues from our other operations from our sale to Chesapeake of natural gas compression units, accessories and equipment produced by our manufacturing subsidiary. Substantially all of the revenue that we earn from the sale of compression units is based on the particular specifications of the compression units purchased by Chesapeake.

The Costs of Conducting Our Business

The principal expenses involved in conducting our business are labor costs, the costs of maintaining and repairing our equipment, rig lease expenses and product and material costs. We also plan to make expenditures for equipment acquisitions and are required to make expenditures to service our debt.

Direct labor costs represented approximately 35%, 35% and 37% of our revenues in 2011, 2010 and 2009, respectively. The decrease in direct labor costs, as a percentage of revenue, was primarily due to higher utilization of our revenue generating assets, resulting in fixed costs being spread over a higher revenue base.

Repair and maintenance costs are expensed as incurred. These costs represented approximately 10%,10% and 13% of our revenues in 2011, 2010 and 2009, respectively. The decrease in repair and maintenance costs, as a percentage of revenue, was due to the addition of new equipment with lower maintenance requirements.

In a series of transactions since 2006, our predecessor sold a number of drilling rigs and related equipment and entered into a master lease agreement under which it agreed to lease the rigs from the buyer for initial terms of five to ten years. In October 2011, the drilling rig leases were transferred to

 

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Chesapeake Equipment Finance, L.L.C. (“CEF”), a wholly owned subsidiary of Chesapeake, and were then subleased to us on terms consistent with those in the original leases. As of December 31, 2011, we leased 93 rigs under these arrangements. The rig leases and subleases contain provisions that permit CEF and us to acquire the related rig from the lessor, in some cases at any time we request and in some cases at the end of the term of the lease. Additionally, certain of the leases permit us to extend the lease term at the end of the existing term of the lease. We anticipate that we will generally seek to acquire these leased rigs when we believe it is advantageous and we have access to sufficient capital for us to do so, and we have budgeted $217.5 million in 2013 for this purpose, which amounts are in addition to our budget for growth capital expenditures. For more information regarding the terms of the sale-leaseback transactions and our sublease with CEF, please see “—Contractual Commitments and Obligations,” “Certain Relationships and Related Party Transactions—Drilling Rig Sale-Leaseback Transactions” and Note 6 “Commitments and Contingencies” to our audited combined financial statements.

We have agreements with Chesapeake pursuant to which Chesapeake allocates certain expenses to us. Under our administrative services agreement with Chesapeake, in return for the general and administrative services provided by Chesapeake, we reimburse Chesapeake on a monthly basis for the overhead expenses incurred by Chesapeake on our behalf in accordance with its current allocation policy, which includes actual out-of-pocket fees, costs and expenses incurred in connection with the provision of any of the services under the agreement, including the wages and benefits of Chesapeake employees who perform services on our behalf. Under our facilities lease agreement with Chesapeake, in return for the use of certain yards and other physical facilities out of which we conduct our operations, we pay rent and our proportionate share of maintenance, operating expenses, taxes and insurance to Chesapeake on a monthly basis. See “Certain Relationships and Related Party Transactions.”

How We Evaluate Our Operations

Our management team uses a variety of tools to monitor and manage our operations in the following five areas: (a) Adjusted EBITDA, (b) asset utilization, (c) equipment maintenance performance, (d) service quality, and (e) safety performance.

Adjusted EBITDA.    A key financial and operating measurement that our management uses to analyze and monitor the operating performance of our business is Adjusted EBITDA, which consists of net income before interest, income taxes, depreciation and amortization, as further adjusted to add back gain or loss on sale of property and equipment and impairments. For additional information about this measure and a reconciliation of our Adjusted EBITDA to our net income, the most directly comparable GAAP financial measure, see footnote 1 to the table in “Prospectus Summary—Summary Historical Financial Data.” The table below shows our Adjusted EBITDA for 2009, 2010 and 2011. Adjusted EBITDA includes $94.1, $94.8 and $105.6 of operating lease expenses associated with our lease of drilling rigs for 2009, 2010 and 2011, respectively. Management considers a majority of these expenses to be financing costs because the underlying sale-leaseback transactions are a form of financing.

 

     Year Ended December 31,  
     2009      2010      2011  
     (Unaudited)  

Adjusted EBITDA

   $ 76,089       $ 121,488       $ 276,926   

Asset utilization.    We believe that our relationship with Chesapeake will allow us to maintain industry-leading asset utilization through industry cycles. We measure our activity levels by the total number of jobs completed by each of our drilling rigs and hydraulic fracturing fleets on a monthly basis. By consistently monitoring the activity level, pricing and relative performance of each of our rigs and fleets, we can more efficiently allocate our personnel and equipment to maximize revenue generation. During the year ended December 31, 2011, the utilization of our drilling rig fleet was 98%. The

 

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utilization rates of our other assets are directly correlated with our rig utilization rates because the well drilling performed by our rigs creates demand for most of the other services we provide.

Equipment maintenance performance.    Although our assets across all of our operating segments are modern and well maintained, preventative maintenance on our equipment remains an important factor in our profitability. If our equipment is not maintained properly, our repair costs may increase and, during periods of high activity, our ability to operate efficiently could be significantly diminished due to having trucks and other equipment out of service. Our maintenance crews perform regular inspections and preventative maintenance on our drilling rigs, hydraulic fracturing fleets, rental equipment, trucks and other mechanical equipment. Our management monitors the performance of our maintenance crews at each of our service locations by reviewing ongoing inspection and maintenance activity and monitoring the level of maintenance expenses as a percentage of revenue. A rising level of maintenance expenses as a percentage of revenue at a particular service location can be an early indication that our preventative maintenance schedule is not being followed. In this situation, management can take corrective measures to help reduce maintenance expenses as well as ensure that maintenance issues do not interfere with operations. Our repair and maintenance costs represented approximately 10% of our revenues for the year ended December 31, 2011.

Service quality.    Our unique relationship with Chesapeake creates operational efficiencies that our competitors cannot replicate. We have access to the budgets and forecasts prepared by Chesapeake and we maintain close communications with Chesapeake regarding its service needs, which together allows us to provide timely, tailored, “just-in-time” service to Chesapeake. Chesapeake evaluates our performance under various criteria and comments on its overall satisfaction level with our equipment, personnel and services. This feedback gives our management valuable information from which to identify performance issues and trends. Our management also uses this information to evaluate our position relative to our competitors in the various markets in which we operate.

Safety performance.    Maintaining a strong safety record is a critical component of our operational success. Our relationship with Chesapeake provides us with enhanced utilization across industry cycles, which in turn reduces employee turnover, increases safety and drives superior results. In addition, the continuity of working relationships between our employees and Chesapeake provides for greater communication and data sharing at our drill sites, which we believe results in safer working conditions for employees. We maintain a safety database that our management uses to identify negative trends in operational incidents so that appropriate measures can be taken to maintain and enhance our safety standards.

Strategic Transactions

Our business has grown organically and through acquisitions. On November 18, 2011, we acquired Horizon Oilfield Services (“Horizon”) for $17.5 million. Included in this acquisition were 38 well site trailers and associated equipment, training and development programs and certain other intellectual property, and approximately 185 experienced employees.

On June 6, 2011, we acquired Bronco Drilling Company, Inc. (“Bronco”) for $339.2 million, adding 22 drilling rigs to our rig count.

On December 15, 2010, we acquired all of the membership interests in Forrest Rig Company, L.L.C. and Forrest Top Drive, L.L.C. (collectively, “Forrest”) for $84.5 million. Included in this acquisition were seven drilling rigs and related equipment.

 

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Results of Operations

Years Ended December 31, 2011, 2010 and 2009

The following table sets forth our consolidated statements of operations for the years ended December 31, 2011, 2010 and 2009.

 

    Years Ended December 31,  
    2011     2010     2009  
    ($ in thousands)  

Revenues, Including Revenue From Affiliates

  $ 1,303,496      $ 815,756      $ 650,279  

Operating Expenses:

     

Operating costs

    987,032        666,924        556,008   

Depreciation and amortization

    171,908        106,425        70,429   

General and administrative, including expenses from affiliates

    37,074        25,312        17,735   

Gains on sales of property and equipment

    (3,571     (854     (1,551

Impairments

    2,729        9        26,797   
 

 

 

   

 

 

   

 

 

 

Total Operating Expenses

    1,195,172        797,816        669,418   
 

 

 

   

 

 

   

 

 

 

Operating Income (Loss)

    108,324        17,940        (19,139
 

 

 

   

 

 

   

 

 

 

Other Income (Expense):

     

Interest including expenses from affiliates

    (65,072     (38,511     (23,453

Losses from equity investee

    —          (2,243     (164

Other income (expense)

    (2,464     211        (283
 

 

 

   

 

 

   

 

 

 

Total Other Income (Expense)

    (67,536     (40,543     (23,900
 

 

 

   

 

 

   

 

 

 

Income (Loss) Before Income Taxes

    40,788        (22,603     (43,039

Income Tax Expense (Benefit)

    21,030        (3,751     (2,656
 

 

 

   

 

 

   

 

 

 

Net Income (Loss)

    19,758        (18,852     (40,383
 

 

 

   

 

 

   

 

 

 

Less: Net (Loss) Attributable To Noncontrolling Interest

    (154     (639     —     
 

 

 

   

 

 

   

 

 

 

Net Income (Loss) Attributable To COS Holdings, L.L.C.

  $ 19,912      $ (18,213   $ (40,383
 

 

 

   

 

 

   

 

 

 

General.    For the years ended December 31, 2011, 2010 and 2009, we had net income (loss) of $19.8 million, ($18.9) million and ($40.4) million, respectively. The increase in net income was primarily due to the growth of revenue generating assets and an increase in drilling activity by Chesapeake, while at the same time increasing operating margins. The increase in operating margins was due to the growth of higher margin product and service offerings and increased pricing.

Revenues.    For the years ended December 31, 2011, 2010 and 2009, we had revenues of $1.303 billion, $815.8 million and $650.3 million, respectively. The increase in revenues from 2010 to 2011 and 2009 to 2010 was due to an increase in our revenue generating assets and increased drilling activity in oil and liquids-rich plays by Chesapeake. Substantially all of our revenues are derived from affiliates.

Our revenues, income (loss) before income taxes and assets are primarily attributable to our four reportable business segments. Each of these segments represents a distinct type of business. These segments have separate management teams that report to our chief operating decision maker. The results of operations in these segments are regularly reviewed by the chief operating decision makers for purposes of determining resource allocation and assessing performance. The following is a description of our segments, as well as our other operations.

Our drilling segment provides premium land drilling and drilling-related services, including directional drilling, geosteering and mudlogging, for oil and natural gas exploration and development activities. As of March 31, 2012, we operated a fleet of 111 land drilling rigs.

 

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Our hydraulic fracturing segment provides hydraulic fracturing services. Hydraulic fracturing involves pumping fluid down a well casing or tubing under high pressure to cause the underground formation to crack, allowing the oil or natural gas to flow more freely. As of March 31, 2012, we owned four hydraulic fracturing fleets with an aggregate of 140,000 horsepower.

Our oilfield rentals segment provides premium rental tools for land oil and natural gas drilling and workover activities. We offer a number of products and services, including drill pipe, drill collars, tubing, high and low pressure blowout preventers, frac and mud tanks and also provide air drilling services and services associated with the transfer of fresh water to the well site.

Our oilfield trucking segment provides rig relocation and logistics services as well as fluid hauling services. As of March 31, 2012, we owned a fleet of 227 rig relocation trucks, 57 cranes and forklifts used in the movement of drilling rigs and 157 fluid hauling trucks.

Our other operations reportable segment primarily consists of our natural gas compressor manufacturing operations.

Our segment revenues for the years ended December 31, 2011, 2010 and 2009 are detailed below:

 

     Years Ended December 31,  
     2011      2010      2009  
     ($ in thousands)  

Drilling

   $ 854,768       $ 572,325       $ 511,427   

Hydraulic Fracturing

     13,005         —           —     

Oilfield rentals

     245,666         121,411         55,764   

Oilfield trucking

     127,042         74,281         40,986   

Other operations

     63,015         47,739         42,102   
  

 

 

    

 

 

    

 

 

 

Total

   $ 1,303,496       $ 815,756       $ 650,279   
  

 

 

    

 

 

    

 

 

 

 

  Ÿ  

Drilling.    Drilling revenues for the year ended December 31, 2011, increased $282.5 million, or 49%, to $854.8 million from $572.3 million for the year ended December 31, 2010. This increase was primarily due to a 17% increase in average day rates in 2011. We also experienced an increase in our average number of operating rigs from 83 to 104 for the years ended December 31, 2010 and 2011, respectively, due primarily to the Bronco acquisition. Our utilization rate increased from 97% to 98% for the years ended December 31, 2010 and 2011, respectively.

Drilling revenues for the year ended December 31, 2010, increased $60.9 million, or 12%, to $572.3 million from $511.4 million for the year ended December 31, 2009. This increase was primarily due to an 8% increase in average day rates in 2010. We also experienced an increase in our average number of operating rigs from 79 to 83 for the years ended December 31, 2009 and 2010, respectively. Our utilization rate increased from 95% to 97% for the years ended December 31, 2009 and 2010, respectively.

 

  Ÿ  

Hydraulic Fracturing.    Hydraulic fracturing revenues for the year ended December 31, 2011 were $13.0 million. In 2010, Chesapeake began the process of establishing a hydraulic fracturing business. We had one hydraulic fracturing fleet with an aggregate of 30,000 horsepower become operational in October 2011. Our second hydraulic fracturing fleet became operational in January 2012, and we anticipate having 12 fleets with an aggregate of approximately 450,000 horsepower by the end of 2013.

 

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  Ÿ  

Oilfield Rentals.    Oilfield rental revenues for the year ended December 31, 2011 increased $124.3 million, or 102%, to $245.7 million from $121.4 million for the year ended December 31, 2010. Oilfield rentals revenue for the year ended December 31, 2010 increased $65.6 million, or 118%, to $121.4 million from $55.8 million for the year ended December 31, 2009. These increases are primarily due to an increase in our revenue generating assets. We also experienced increased utilization due to an increase in drilling activity by Chesapeake and third parties. The utilization of our oilfield rental equipment has historically coincided with fluctuations in our drilling activity.

 

  Ÿ  

Oilfield Trucking.    Oilfield trucking revenues for the year ended December 31, 2011 increased $52.7 million, or 71%, to $127.0 million from $74.3 million for the year ended December 31, 2010. The increase in revenue from 2010 to 2011 is due to an increase in the utilization and size of our trucking fleet, with the increase in utilization being attributable to the increase in drilling activity by Chesapeake. Oilfield trucking revenue for the year ended December 31, 2010 increased $33.3 million, or 81%, to $74.3 million from $41.0 million for the year ended December 31, 2009. This increase in revenue from 2009 to 2010 is primarily due to increased utilization resulting from an increase in drilling activity by Chesapeake.

 

  Ÿ  

Other Operations.    Our other operations consist primarily of our compression unit manufacturing business. For the year ended December 31, 2011, revenues from our other operations increased $15.3 million, or 32%, to $63.0 million from $47.7 million for the year ended December 31, 2010. For the year ended December 31, 2010, revenues from our other operations increased $5.6 million, or 13%, to $47.7 million from $42.1 million for the year ended December 31, 2009. These increases are primarily due to an increase in our overall compression unit manufacturing capacity and increased demand by Chesapeake.

Operating Costs.    Operating costs for the years ended December 31, 2011, 2010 and 2009 were $987.0 million, $666.9 million and $556.0 million, respectively. The increase in operating costs is due to an increase in drilling activity in liquids-rich plays by Chesapeake, which resulted in higher labor, rental, repairs and maintenance, supplies and other operating costs. As a percentage of revenues, operating costs were 76%, 82% and 86% for the years ended December 31, 2011, 2010 and 2009, respectively. The decrease in operating costs as a percentage of revenues is primarily attributable to higher utilization and rates charged for our revenue generating assets resulting in fixed costs being spread over a higher revenue base. Our segment operating costs for the years ended December 31, 2011, 2010 and 2009 are detailed below:

 

     Years Ended December 31,  
     2011      2010      2009  
     ($ in thousands)  

Drilling

   $ 685,563       $ 482,808       $ 435,789   

Hydraulic fracturing

     21,787         —           —     

Oilfield rentals

     115,286         78,631         38,439   

Oilfield trucking

     109,098         60,621         41,750   

Other operations

     55,298         44,864         40,030   
  

 

 

    

 

 

    

 

 

 

Total

   $ 987,032       $ 666,924       $ 556,008   
  

 

 

    

 

 

    

 

 

 

 

  Ÿ  

Drilling.    Drilling operating costs for the year ended December 31, 2011, increased $202.8 million, or 42%, to $685.6 million from $482.8 million for the year ended December 31, 2010. This increase was primarily due to an increase in our average number of operating rigs from 83 to 104 for the years ended December 31, 2010 and 2011, respectively. The increase in our average number of operating rigs is primarily due to the Bronco acquisition. The increase in our average number of operating rigs resulted in higher labor costs, repairs and maintenance and other operating costs. We also experienced an increase in our utilization rate from 97% to 98% for the years ended December 31, 2010 and 2011, respectively. As a percentage of

 

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drilling revenues, drilling operating costs decreased from 84% to 80% for the years ended December 31, 2010 and 2011, respectively. This decrease is primarily attributable to rig rental expense related to leased rigs decreasing as a percentage of revenue which is the result of the Bronco acquisition and our owning a higher percentage of our operating rigs.

Drilling operating costs for the year ended December 31, 2010, increased $47.0 million, or 11%, to $482.8 million from $435.8 million for the year ended December 31, 2009. This increase was primarily due to an increase in our average number of operating rigs and higher utilization. Our average number of operating rigs increased from 79 to 83 for the years ended December 31, 2009 and 2010, respectively. The increase in our average number of operating rigs resulted in higher labor costs and other operating costs. Our utilization rate increased from 95% to 97% for the years ended December 31, 2009 and 2010, respectively, as we experienced an increase in demand for our drilling services. As a percentage of drilling revenues, drilling operating costs decreased from 85% to 84% for the years ended December 31, 2009 and 2010.

 

  Ÿ  

Hydraulic Fracturing.    Hydraulic fracturing operating costs for the year ended December 31, 2011 were $21.8 million. As a percentage of hydraulic fracturing revenue, operating costs were 168% for the year ended December 31, 2011 due primarily to labor costs incurred prior to our hydraulic fracturing fleets becoming operational.

 

  Ÿ  

Oilfield Rentals.    Oilfield rental operating costs for the year ended December 31, 2011 increased $36.7 million, or 47%, to $115.3 million from $78.6 million for the year ended December 31, 2010 due to an increase in drilling activity. Oilfield rental operating costs for the year ended December 31, 2010 increased $40.2 million, or 105%, to $78.6 million from $38.4 million for the year ended December 31, 2009. These year over year increases were primarily due to an increase in drilling activity which resulted in higher labor, supplies, repairs and maintenance, freight and third-party expenses. As a percentage of oilfield rental revenues, oilfield rental operating costs were 47%, 65% and 69% for the years ended December 31, 2011, 2010 and 2009, respectively. The reductions in operating costs as a percentage of revenues is primarily attributable to higher utilization of our rental tools resulting in the allocation of fixed costs over a larger revenue base.

 

  Ÿ  

Oilfield Trucking.    Oilfield trucking operating costs for the year ended December 31, 2011 increased $48.5 million, or 80%, to $109.1 million from $60.6 million for the year ended December 31, 2010. Oilfield trucking operating costs for the year ended December 31, 2010 increased $18.8 million, or 45%, to $60.6 million from $41.8 million for the year ended December 31, 2009. These increases are primarily due to an increase in drilling activity, which resulted in higher labor, fuel and repairs and maintenance expense. As a percentage of oilfield trucking revenue, oilfield trucking operating costs were 86%, 82% and 102% for the years ended December 31, 2011, 2010 and 2009, respectively. The increase in oilfield trucking operating costs as a percentage of oilfield trucking revenues from 2010 to 2011 is primarily attributable to our utilizing third parties for longer rig moves, which compressed our margins. The reduction in oilfield trucking operating costs as a percentage of oilfield trucking revenues from 2009 to 2010 is primarily attributable to higher utilization of our trucking fleet resulting in fixed labor costs being spread over a larger revenue base.

 

  Ÿ  

Other Operations.    Our other operations consist primarily of our compression unit manufacturing business. For the year ended December 31, 2011, operating costs for our other operations increased $10.4 million, or 23%, to $55.3 million from $44.9 million for the year ended December 31, 2010. For the year ended December 31, 2010, operating costs for our other operations increased $4.9 million, or 12%, to $44.9 million from $40.0 million for the year ended December 31, 2009. These increases are primarily due to an increase in our overall compression unit manufacturing capacity and increased demand by Chesapeake, which resulted in higher costs of goods sold.

 

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Depreciation and Amortization.    Depreciation and amortization for the years ended December 31, 2011, 2010 and 2009 was $171.9 million, $106.4 million and $70.4 million, respectively. The increases reflect the overall increase in the size of and investment in our asset base as the result of capital expenditures.

General and Administrative Expenses.    General and administrative expenses for the years ended December 31, 2011, 2010 and 2009 were $37.1 million, $25.3 million and $17.7 million, respectively. The increase is due to additional charges from Chesapeake for indirect corporate overhead to cover costs of functions such as legal, accounting, treasury, environmental safety, information technology and other corporate services related to our overall increase in operating activity.

Gains on Sales of Property and Equipment.    We recorded a net gain on the sales of property and equipment of $3.6 million, $0.9 million and $1.6 million during the year ended December 31, 2011, 2010 and 2009, respectively.

Impairments.    Management determined in the fourth quarter of 2011 to sell certain drill pipe used in our oilfield rentals business. Because the assets met the held-for-sale criteria, we are required to present such assets at the lower of carrying amount or fair value less the anticipated costs to sell. We evaluated these assets for impairment as of December 31, 2011, which resulted in us recognizing a $2.6 million impairment charge. Our fair value estimate was derived from bids received from interested parties. After the impairment charge, the assets had a carrying value of $1.4 million at December 31, 2011 and are included in assets held for sale in our consolidated balance sheets.

There was a significant adverse change in the economic and business climate as financial markets reacted to the credit crisis facing major lending institutions and worsening conditions in the overall economy throughout 2009. During the same time, there were significant declines in oil and natural gas prices which led to declines in service revenues, margins and cash flows. We considered the impact of these significant adverse changes in the economic and business climate as we performed our annual impairment assessment of goodwill in 2009. The estimated fair value of our oilfield trucking segment was negatively impacted by significant reductions in estimated cash flows, and we concluded that there would be no remaining implied fair value attributable to this goodwill. Accordingly, we recorded a non-cash impairment charge of $19.8 million in our operating results for the year ended December 31, 2009.

Our wholly owned subsidiary, Nomac, entered into an equipment purchase agreement with LeTourneau Technologies Drilling Systems, Inc. (“LTDSI”) in June 2008 to purchase nine drilling rigs and related equipment for $90.2 million. We made down payments totaling $22.5 million during 2008 in accordance with the agreement. LTDSI filed suit against Nomac in December 2008 related to a dispute involving the equipment purchase agreement. In 2009, the equipment purchase agreement was terminated and LTDSI agreed to deliver certain rig equipment with an estimated fair value of $15.5 million in exchange for retaining the down payment made by Nomac. We recorded an impairment of long-lived assets in the amount of $7.0 million for the year ended December 31, 2009, equal to the down payments less the fair value of the equipment received.

Interest Expense.    Interest expense for the years ended December 31, 2011, 2010 and 2009 was $65.1 million, $38.5 million and $23.5 million, respectively. The increase is due in part to an increase in our average long-term debt of $841.9 million, $564.8 million and $359.0 million for the years ended December 31, 2011, 2010 and 2009, respectively. We entered into our revolving bank credit facility and issued our 2019 Senior Notes during the fourth quarter of 2011. Interest is capitalized on the average amount of accumulated expenditures for significant capital projects under construction using the effective interest rate of our debt until the underlying assets are placed into service. The capitalized interest is added to the cost of the assets and amortized to depreciation expense over the

 

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useful life of the assets. For the years ended December 31, 2011, 2010 and 2009, we capitalized interest of approximately $0.9 million, $0.6 million and $2.8 million, respectively.

Losses from Equity Investee.    Losses from equity investees were $0.0, $2.2 million and $0.2 million for the years ended December 31, 2011, 2010 and 2009, respectively.

Other Income (Expense).    Other income (expense) was ($2.5) million, $0.2 million and ($0.3) million in for the years ended December 31, 2011, 2010 and 2009.

Income Tax Expense (Benefit).    We recorded income tax expense (benefit) of $21.0 million, ($3.8) million and ($2.7) million for the years ended December 31, 2011, 2010 and 2009, respectively. The $24.8 million increase in income tax expense recorded for the year ended December 31, 2011 was primarily the result of an increase in net income before income taxes of $63.4 million from the year ended December 31, 2010. The $1.1 million increase in income tax benefit recorded for the year ended December 31, 2010 was primarily the result of a decrease in unfavorable permanent differences, partially offset by a decrease in net loss before income taxes of $20.4 million from the year ended December 31, 2009.

Liquidity and Capital Resources

We require capital to fund ongoing operations, including operating expenses, organic growth initiatives, investments, acquisitions and debt service. Additionally, we plan to make significant capital expenditures on equipment during the next two years. Historically, Chesapeake has provided regular capital infusions to help fund our business activities. We anticipate that our future capital needs will be provided for by cash flows from operations, borrowings under our revolving bank credit facility, access to capital markets and other financing transactions. If these sources of capital are not available or are not available on an economic basis, we would be required to reduce our expenditures, which would likely cause us not to meet our growth objectives or could otherwise adversely affect us.

Our $500.0 million senior secured revolving bank credit facility is an important source of liquidity for us. The maximum amount that we may borrow under the facility may be subject to limitation due to the operation of the covenants contained in the facility. The revolving credit facility allows us to request increases in the total commitments under the facility by up to $400.0 million in the aggregate in part or in full anytime during the term of the revolving credit facility, with any such increases being subject to compliance with the restrictive covenants in the revolving bank credit facility and in the indenture governing our 2019 Senior Notes, as well as lender approval. The revolving bank credit facility matures on November 3, 2016. For a more complete description of our revolving bank credit facility, please read “Description of Certain Indebtedness—Revolving Bank Credit Facility.”

Capital Expenditures

Capital expenditures (including acquisitions) were $738.4 million, $269.8 million and $325.9 million for the years ended December 31, 2011, 2010 and 2009, respectively.

We currently expect our growth capital expenditures to be between $1.1 billion and $1.2 billion over the next two years, and we expect to make these expenditures to grow our business lines, particularly our fleets and rental tool inventory. Additionally, we have budgeted $217.5 million in 2013 to acquire certain of our leased drilling rigs, which we plan to do when we believe it is advantageous and we have access to sufficient capital for us to do so. We may increase, decrease or re-allocate our anticipated capital expenditures during any period based on industry conditions, the availability of attractive capital or other factors, and we believe that a significant component of our anticipated capital spending is discretionary.

 

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Cash Flows

Our cash flows depend, to a large degree, on the level of spending by Chesapeake for exploration, development and production activities. Sustained increases or decreases in the price of oil or natural gas could have a material impact on these activities, thus materially affecting our cash flows. The following is a discussion of our cash flows for the years ended December 31, 2011, 2010 and 2009.

The table below summarizes our cash flows for the years ended December 31, 2011, 2010 and 2009.

 

     Years Ended December 31,  
     2011     2010     2009  
     (In thousands)  

Cash flow provided by operating activities

   $ 211,086      $ 91,284      $ 25,720   

Cash flow (used in) investing activities

   $ (644,109   $ (223,331   $ (322,910

Cash flow provided by financing activities

   $ 435,013      $ 132,181      $ 297,129   

Cash, beginning of period

   $ 370      $ 236      $ 297   

Cash, end of period

   $ 2,360      $ 370      $ 236   

Operating Activities.    Cash provided by operating activities was $211.1 million, $91.3 million and $25.7 million for the years ended December 31, 2011, 2010 and 2009, respectively. Net income (loss) adjusted for non-cash components was approximately $213.4 million, $90.0 million and $56.2 million for the years ended December 31, 2011, 2010 and 2009, respectively. Additionally, changes in working capital items provided (used) were $(2.3) million, $1.3 million and ($30.5) million in cash flows for the years ended December 31, 2011, 2010 and 2009, respectively. Factors affecting changes in operating cash flows are largely the same as those that affect net income, with the exception of non-cash expenses such as depreciation and amortization, amortization of sale-leaseback gains, gains or losses on sales of property and equipment, impairments, stock-based compensation, losses from equity investee and deferred income taxes.

Investing Activities.    Cash used in investing activities was $644.1 million, $223.3 million and $322.9 million for the years ended December 31, 2011, 2010 and 2009, respectively. Capital expenditures are the main component of our investing activities. Capital expenditures (including acquisitions) were $738.4 million, $269.8 million and $325.9 million for the years ended December 31, 2011, 2010 and 2009, respectively. See “—Capital Expenditures.”

In November 2011, we acquired Horizon for $17.5 million. In June 2011, we acquired Bronco for $322.5 million, net of $16.7 million of cash acquired, which added 22 operating drilling rigs to our rig count. In addition to the Bronco and Horizon acquisitions in 2011, we spent $395.3 million on drilling rigs and related equipment, rental tools, hydraulic fracturing equipment, rig relocation trucks and other property and equipment.

We had additions to investments of $16.7 million for the year ended December 31, 2011. On October 7, 2011, we acquired 49% of the membership interests in Maalt Specialized Bulk, L.L.C. (“Maalt”) for $12.0 million. Maalt provides bulk transportation, transloading and sand hauling services, and its assets consist primarily of 125 trucks and 122 trailers.

On August 24, 2011, we entered into a joint venture agreement with Big Star Field Services, L.L.C. to form Big Star Crude Co., L.L.C. (“Big Star”), which is engaged in the commercial trucking business. Pursuant to the joint venture agreements, we contributed 85% of the capital requirements of this entity, which was approximately $7.1 million, making our portion approximately $6.1 million. We

 

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own 49% of the equity in Big Star Crude and will receive a preferred return (85% of cash flow) until a 25% rate of return has been reached at which time the distribution will be based on actual equity ownership.

In December 2010, we acquired Forrest for $35.0 million in cash and issued a note payable for $49.5 million. We acquired seven drilling rigs and related equipment in the transaction. In addition to the Forrest acquisition, in 2010 we spent $233.2 million on drilling rigs and related equipment, rental tools, hydraulic fracturing equipment, rig relocation trucks and other property and equipment.

In 2009, we spent $325.9 million on drilling rigs and related equipment, rental tools, rig relocation trucks and other property and equipment.

Cash used in investing activities was partially offset by proceeds from sales of assets in the amounts of $110.9 million, $46.4 million and $6.0 million for the years ended December 31, 2011, 2010 and 2009, respectively. We sold eight drilling rigs and related equipment during 2011 and three drilling rigs and related equipment during 2010 for proceeds of $96.9 million and $40.4 million, respectively, and entered into master lease agreements under which we agreed to lease the rigs from the buyers for initial terms of five to seven years.

Financing Activities.    Net cash provided by financing activities was $435.0 million, $132.2 million and $297.1 million for the years ended December 31, 2011, 2010 and 2009, respectively. On November 3, 2011, we entered into a five-year $500.0 million senior secured revolving bank credit facility. We had borrowings and payments on the revolving credit facility of $168.0 million and $139.0 million during 2011, respectively. On October 28, 2011, we issued $650.0 million principal amount of the 2019 Senior Notes in a private placement. We used the net proceeds of $637.0 million to repay a portion of our affiliate debt with Chesapeake. We incurred $7.2 million in deferred financing costs related to our revolving credit facility and 2019 Senior Notes. For a description of our revolving bank credit facility and our 2019 Senior Notes, please read “Description of Certain Indebtedness.” We made payments on third-party notes payable in the amount of $55.2 million in 2011, primarily related to the Forrest note described above.

We also had decreases in our affiliate debt with Chesapeake during 2011 in the amount of $168.6 million. The capital intensive nature of the oilfield service business has historically required Chesapeake to provide regular capital infusions to fund our activities. Cash provided by financing activities for 2010 and 2009 consists primarily of increases in our affiliate debt.

 

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Contractual Commitments and Obligations

In the normal course of business, we enter into various contractual obligations that impact, or could impact, our liquidity. The following table summarizes our material obligations at December 31, 2011, with projected cash payments in the years shown:

 

     Payments Due by Period  
     Total      Less Than
1 Year
     1-3 Years      4 - 5 Years      More Than
5 Years
 
     (Unaudited)  
     (In thousands)  

Long-Term Debt:

              

Affiliate debt(a)

     371,674         —           —           371,674         —     

6.625% Senior Notes due 2019(b)

     650,000         —           —           —           650,000   

Revolving Bank Credit Facility(b)

     29,000         —           —           29,000         —     

Interest(c)

     346,860         45,304         86,125         86,243         129,188   

Purchase obligations(d)

     280,473         255,367         25,106         —           —     

Operating leases(e)

     502,320         123,936         237,714         115,094         25,576   
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Total

   $ 2,180,327       $ 424,607       $ 348,945       $ 602,011       $ 804,764   
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

 

(a) Represents a revolving note with Chesapeake, the balance of which is expected to be repaid with proceeds from this offering.
(b) Represents long-term debt obligations of our indirect wholly owned subsidiary, COO. See “Description of Certain Indebtedness.”
(c) Amount primarily includes contractual interest payments on the 2019 Senior Notes.
(d) Consists of nonconditional obligations to purchase equipment. See Note 6 to our Consolidated Financial Statements.
(e) Consists primarily of drilling rig and related equipment leases. Amounts disclosed assume no exercise of options to renew or extend the leases.

In a series of transactions since 2006, our predecessor sold 93 drilling rigs and related equipment and entered into a master lease agreement under which it agreed to lease the rigs from the buyer for initial terms of five to ten years. In October 2011, the drilling rig leases were transferred to CEF, a wholly owned subsidiary of Chesapeake, and were then subleased to us on terms consistent with those in the original leases. CEF’s lease obligations are guaranteed by Chesapeake and certain of its subsidiaries. Under the rig leases, CEF has the right to exercise the early purchase option provided for in the leases after five and one-half to seven years or on the expiration of the lease term for a purchase price equal to the then fair market value of the rigs. Under certain rig leases, CEF can exercise a purchase option at any time, and pursuant to a drilling rig repurchase agreement, we can require CEF to exercise its purchase option. Additionally, in most cases CEF has the option to renew the rig lease for a negotiated renewal term at a periodic lease payment equal to the fair market rental value of the rigs as determined at the time of renewal. For more information regarding the terms of the sale-leaseback transactions and our sublease with CEF, please see “Certain Relationships and Related Party Transactions—Drilling Rig Sale-Leaseback Transactions” and Note 6 “Commitments and Contingencies” to our audited consolidated financial statements.

On October 1, 2011 we entered into our facilities lease agreement with Chesapeake to lease certain administrative offices and operational facilities in various cities for an initial term of approximately three years. The lease will automatically renew for successive one year terms unless an election is made to terminate by either party. This lease is being treated as an operating lease.

In December 2011, we entered into six lease agreements with various third parties to lease rail cars for initial terms of six months to five years. Additional rental payments are required for the use of rail cars in excess of the allowable mileage stated in the respective agreement. These leases are being treated as operating leases.

 

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Aggregate undiscounted minimum future lease payments under our noncancelable operating leases are presented below:

 

     December 31, 2011  
     Rigs      Real Property      Rail Cars      Total  
     ($ in thousands)  

2012

   $ 109,904       $ 8,273       $ 5,759       $ 123,936   

2013

     112,105         8,273         6,005         126,383   

2014

     97,873         8,273         5,185         111,331   

2015

     39,424         —           4,481         43,905   

2016

     67,139         —           4,050         71,189   

After 2016

     25,576         —           —           25,576   
  

 

 

    

 

 

    

 

 

    

 

 

 

Total

   $ 452,021       $ 24,819       $ 25,480       $ 502,320   
  

 

 

    

 

 

    

 

 

    

 

 

 

Off-Balance Sheet Arrangements

We have no off-balance sheet arrangements, other than drilling rig subleases and other customary operating leases included in the table above, that have or are likely to have a current or future material effect on our financial condition, changes in financial condition, revenues, expenses, results of operations, liquidity, capital expenditures or capital resources.

Critical Accounting Policies

Our consolidated financial statements are prepared in accordance with generally accepted accounting principles, which require us to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the dates of the financial statements and the reported amounts of revenues and expenses during the reported periods. We have provided a description of all of our significant accounting policies in Note 2 to our audited consolidated financial statements included elsewhere in this prospectus. We believe that of these significant policies, the following may involve a higher degree of judgment or complexity.

Property and Equipment

Property and equipment are carried at cost less accumulated depreciation. Depreciation is calculated using the straight-line method, based on estimates, assumptions and judgments relative to the assets’ estimated useful lives and salvage values. These estimates are based on various factors, including age (in the case of acquired assets), manufacturing specifications, technological advances and historical data concerning useful lives of similar assets. Upon the disposition of an asset, we eliminate the cost and related accumulated depreciation and include any resulting gain or loss in the consolidated statements of operations as (gains) losses on the sale of property and equipment. Expenditures for maintenance and repairs that do not add capacity or extend the useful life of an asset are expensed as incurred.

Interest is capitalized on the average amount of accumulated expenditures for significant capital projects under construction using the effective interest rate of our debt until the underlying assets are placed into service. The capitalized interest is added to the cost of the assets and amortized to depreciation expense over the useful life of the assets.

Impairment of Long-Lived Assets

We review our long-lived assets, such as property and equipment, whenever, in management’s judgment, events or changes in circumstances indicate the carrying amount of the assets may not be

 

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recoverable. Factors that might indicate a potential impairment include a significant decrease in the market value of the long-lived asset, a significant change in the long-lived asset’s physical condition, a change in industry conditions or a reduction in cash flows associated with the use of the long-lived asset. If these or other factors indicate the carrying amount of the asset may not be recoverable, we determine whether an impairment has occurred through analysis of the undiscounted cash flow of the asset. If an impairment has occurred, we recognize a loss for the difference between the carrying amount and the fair market value of the asset. We measure the fair value of the asset using market prices or, in the absence of market prices, based on an estimate of discounted cash flows. Cash flows are generally discounted using an interest rate commensurate with a weighted average cost of capital for a similar asset.

Goodwill, Intangible Assets and Amortization

Goodwill represents the cost in excess of fair value of the net assets of businesses acquired. Goodwill and intangible assets with indefinite lives are not amortized. Intangible assets with finite lives are amortized on a basis that reflects the pattern in which the economic benefits of the intangible assets are realized, which is generally on a straight-line basis over an asset’s estimated useful life.

We review goodwill and intangible assets with indefinite lives for impairment annually or more frequently if events or changes in circumstances indicate that the carrying amount of the reporting unit exceeds its fair value. Circumstances that could indicate a potential impairment include a significant adverse change in the economic or business climate, a significant adverse change in legal factors, an adverse action or assessment by a regulator, unanticipated competition, loss of key personnel and the likelihood that a reporting unit or significant portion of a reporting unit will be sold or otherwise disposed. Accounting guidance requires a two-step process for testing impairment. First, the fair value of each reporting unit is compared to its carrying value to determine whether an indication of impairment exists. Second, if impairment is indicated, the fair value of the reporting unit’s goodwill is determined by allocating the unit’s fair value to its assets and liabilities (including any unrecognized intangible assets) as if the reporting unit had been acquired in a business combination on the impairment test date. The amount of impairment for goodwill is measured as the excess of the carrying value of the reporting unit over its fair value.

When estimating fair values of a reporting unit for our goodwill impairment test, we use the income approach. The income approach provides an estimated fair value based on the reporting unit’s anticipated cash flows that are discounted using a weighted average cost of capital rate. The primary assumptions used in the income approach are estimated cash flows and weighted average cost of capital. Estimated cash flows are primarily based on projected revenues, operating costs and capital expenditures and are discounted based on comparable industry average rates for weighted average cost of capital.

Revenue Recognition

Substantially all of our revenues are derived from affiliates. Overall, we recognize revenue when services are performed, collection of receivables is probable, persuasive evidence of an arrangement exists and the price is fixed or determinable.

Drilling.    We earn revenues by drilling oil and natural gas wells for our customers under daywork contracts. We recognize revenue on daywork contracts for the days completed based on the dayrate each contract specifies. In the event we enter into footage contacts, we will follow the percentage-of-completion method of accounting for footage drilling arrangements. Under this method, drilling revenues and costs related to a well in progress are recognized proportionately over the time it takes to drill the well. Payments received and costs incurred for mobilization services are recognized over the days of actual mobilization.

 

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Hydraulic Fracturing.    We recognize revenue upon the completion of each fracturing stage. We typically complete one or more fracturing stages per day per active crew during the course of a job. A stage is considered complete when the customer requests or the job design dictates that pumping discontinue for that stage. Invoices typically include a lump sum equipment charge determined by the rate per stage each contract specifies and product charges for sand, chemicals and other products actually consumed during the course of providing our services.

Oilfield Rentals.    We rent many types of oilfield equipment, including drill pipe, drill collars, tubing, blowout preventers, frac and mud tanks, and also provide air drilling services and services associated with the transfer of fresh water to the well site. We price our rentals and services based on the type of equipment being rented and the service job being performed and recognize revenue ratably over the term of the rental.

Oilfield Trucking.    Oilfield trucking provides rig relocation and logistics services as well as fluid hauling services. Our trucks move drilling rigs, crude oil, other fluids and construction materials to and from the well site and also transport produced water from the well site. We price these services by the hour and recognize revenue as services are performed.

Other Operations.    We design, engineer and fabricate natural gas compressor packages that we sell to Chesapeake. We price our compression units based on certain specifications such as horsepower, stages and additional options. We recognize revenue upon the completion and transfer of ownership of the natural gas compression unit.

Income Taxes

Chesapeake and its subsidiaries historically have filed a consolidated federal income tax return and other state returns as required. COS LLC and certain of its subsidiaries, as limited liability companies, are not subject to federal income taxes. For these entities, for federal and state income tax purposes, all income, expenses, gains, losses and tax credits generated flow through to their respective members or partners. Because these items of income or loss ultimately flow up to Chesapeake’s corporate tax return, we have reported income taxes on a separate return basis for COS LLC and all of our subsidiaries. Accordingly, we have recognized deferred tax assets and liabilities for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases for all our subsidiaries, including the limited liability companies as if each entity were a corporation, regardless of its actual characterization for U.S. federal income tax purposes.

A valuation allowance for deferred tax assets is recognized when it is more likely than not that some or all of the benefit from the deferred tax asset will not be realized. To assess that likelihood, we use estimates and judgment regarding our future taxable income, as well as the jurisdiction in which such taxable income is generated, to determine whether a valuation allowance is required. Such evidence can include our current financial position, our results of operations, both actual and forecasted, the reversal of deferred tax liabilities, and tax planning strategies as well as the current and forecasted business economics of our industry. We had no valuation allowance at December 31, 2011 and 2010.

Recent Accounting Pronouncements

In September 2011, the Financial Accounting Standards Board issued revised guidance related to the annual goodwill impairment test. The revised guidance provides both public and non-public entities with the option of performing a qualitative assessment to determine whether further impairment testing is necessary. The revised standard is effective for goodwill impairment tests performed for fiscal years beginning after December 15, 2011. We do not expect this guidance to have a material effect on our financial condition or results of operations.

 

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Inflation

Inflation in the U.S. has been relatively low in recent years and did not have a material impact on our results of operations for the years ended December 31, 2011, 2010 and 2009. Although the impact of inflation has been insignificant in recent years, it is still a factor in the U.S. economy and we tend to experience inflationary pressure on the cost of energy services and equipment as increasing oil and natural gas prices increase activity in our areas of operations.

Quantitative and Qualitative Disclosures About Market Risk

Historically, we have provided substantially all of our oilfield services to Chesapeake. For the years ended December 31, 2011, 2010 and 2009, Chesapeake accounted for approximately 94%, 96% and 95% of our revenues, respectively. Approximately 83% of Chesapeake’s estimated proved reserves volumes as of December 31, 2011 were natural gas and 84% of Chesapeake’s 2011 oil and natural gas sales volumes were from natural gas sales. Sustained low natural gas prices, as has been the case recently, and volatile commodity prices in general, could have a material adverse effect on Chesapeake’s and our financial position, results of operations and cash flows, which could adversely impact our ability to comply with financial covenants under our revolving bank credit facility and further limit our ability to fund our planned capital expenditures.

Changes in interest rates affect the amount of interest we earn on our cash, cash equivalents and short-term investments and the interest rate we pay on borrowings under our revolving bank credit facility. We have borrowings outstanding under and may in the future borrow under fixed rate and variable rate debt instruments that give rise to interest rate risk. For fixed rate debt, changes in interest rates generally affect the fair value of the debt instrument, but not our earnings or cash flows. Conversely, for variable rate debt, changes in interest rates generally do not impact the fair value of the debt instrument, but may affect our future earnings and cash flows. Our fuel costs, which consist primarily of diesel fuel used by our various trucks and other equipment, can expose us to commodity price risk and, as our hydraulic fracturing operations grow, we will face increased risks associated with the prices of materials used in hydraulic fracturing such as sand and chemicals. The prices for fuel and these materials can be volatile and are impacted by changes in supply and demand, as well as market uncertainty and regional shortages.

Our primary exposure to interest rate risk results from outstanding borrowings under our revolving bank credit facility, which COO entered into on November 3, 2011. Outstanding borrowings under our revolving bank credit facility bear interest at our option at either (a) the greater of the reference rate of Bank of America, N.A., the federal funds effective rate plus 0.50%, and one-month LIBOR plus 1.00%, all of which are subject to a margin that varies from 1.00% to 1.75% per annum, according to our leverage ratio, or (b) the Eurodollar rate, which is based on LIBOR plus a margin that varies from 2.00% to 2.75% per annum, according to our leverage ratio. A one percentage point increase or decrease in interest rate payable on our revolving bank credit facility would have resulted in a $0.2 million increase or decrease in net income.

 

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BUSINESS

Our Company

We are a diversified oilfield services company that provides a wide range of well site services primarily to Chesapeake, our founder and principal customer, and its partners. Chesapeake is the most active driller of new oil and natural gas wells in the U.S. based on rig count. We focus on providing services to Chesapeake that are strategic to its oil and gas operations, represent historical bottlenecks to those operations or provide relatively high margins to the service provider, including drilling, hydraulic fracturing, oilfield rentals, oilfield trucking and manufacturing of natural gas compressor packages. Our operations are geographically diversified across most major basins in the U.S. Specifically, we provide Chesapeake and its partners with services in the Eagle Ford, Utica, Granite Wash, Cleveland, Tonkawa, Mississippi Lime, Bone Spring, Avalon, Wolfcamp, Wolfberry, and Niobrara unconventional liquids plays and the Barnett, Haynesville, Bossier, Marcellus and Pearsall natural gas shale plays.

Our objective is to provide up to two-thirds of Chesapeake’s overall expected needs for our current and future services. This objective, combined with our unique relationship with Chesapeake, makes us fundamentally different than our competitors because it provides us with substantial growth opportunities while at the same time positioning us to maintain our industry-leading asset utilization rates. We believe that our high-growth, high-utilization business model will allow us to continue creating significant shareholder value over time.

Our business has grown rapidly since our first subsidiary was founded in 2001, both organically and through acquisitions, and we are now one of the larger U.S. onshore oilfield service companies. We currently operate 111 land drilling rigs, the fourth largest active rig fleet in the U.S., which represents our largest revenue generating service line today. We also operate (a) four hydraulic fracturing fleets with an aggregate of 140,000 horsepower; (b) one of the largest oilfield rental businesses in the U.S.; (c) one of the largest oilfield trucking fleets in the U.S., currently consisting of 227 rig relocation trucks, 57 cranes and forklifts used in the movement of drilling rigs and other heavy equipment and 157 fluid hauling trucks; and (d) manufacturing capacity for up to 150 compressor units per quarter, or approximately 85,000 horsepower in the aggregate per quarter. We continue to grow our assets rapidly and have ordered 12 drilling rigs that will utilize advanced electronic drilling technology, including 10 of our proprietary, fit-for-purpose PeakeRigs, which are scheduled to be delivered at a rate of approximately one rig per month through May 2013. We have also ordered additional new hydraulic fracturing equipment with an aggregate of 175,000 horsepower, and we expect to have eight hydraulic fracturing fleets with an aggregate of 315,000 horsepower operating by the end of 2012 and 12 such fleets with an aggregate of 450,000 horsepower operating by the end of 2013. We believe our growth plans will place us among the largest hydraulic fracturing companies in the U.S. by year-end 2014 based on horsepower.

The services that we provide to Chesapeake are fundamental to establishing and maintaining the production of oil and natural gas from its wells. As of December 31, 2011, Chesapeake had total estimated net proved reserves of approximately 18.8 tcfe, which includes approximately 545 mmbbls of oil and natural gas liquids, which we refer to collectively as “liquids,” and was operating 162 drilling rigs to develop its inventory of approximately 39,000 risked net drill sites. During 2011, Chesapeake utilized hydraulic fracturing fleets with an average of approximately 1.0 million horsepower per day. For 2012 and 2013, Chesapeake’s gross operated drilling and completion capital expenditure budgets are approximately $11.0 billion and $12.0 billion, respectively.

 

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Chesapeake’s operated drilling program includes expenditures by both Chesapeake and its partners. The charts below show the percentage of budgeted capital expenditures expected to be funded by Chesapeake and its partners in 2012 and 2013.

Chesapeake’s Gross Operated Drilling and Completion

Capital Expenditure Budget

 

LOGO

We currently supply Chesapeake with small percentages of its overall requirements for most of our services, which presents us with significant organic growth opportunities. For example, during the year ended December 31, 2011, our revenues from hydraulic fracturing represented less than 1% of Chesapeake’s gross operated expenditures for hydraulic fracturing services and our revenues from oilfield equipment rentals would have represented approximately 19% of its gross operated expenditures for oilfield equipment rentals. Additionally, although we already supply approximately two-thirds of Chesapeake’s current drilling rig needs, we provide low percentages of the drilling-related services it uses, such as directional drilling, mud logging and geosteering services, providing us with significant organic growth opportunities for those services as well. Likewise, while our trucking segment provides Chesapeake with a significant percentage of its rig relocation services, we provide only a small percentage of its fluid hauling requirements.

By seeking to match our productive capacity to meet up to two-thirds of Chesapeake’s expected need for our services, we anticipate that we will continue to have industry-leading asset utilization levels through industry cycles, as we believe that Chesapeake will have a number of incentives to use our services given our relationship and the operational efficiencies we provide. Moreover, Chesapeake’s drilling activity levels over time have been more stable than those of its peers. For example, in the twelve-month period ended September 30, 2009, one of the most challenging periods in the recent history of our industry, the U.S. onshore industry rig count decreased by 1,308 rigs, or 50%, while Chesapeake’s operated rig count, which includes third-party rigs, decreased by only 53 rigs, or 34%. During that same period, Chesapeake’s utilization of our rigs increased by six rigs, from 71 to 77, or 8%. Our rig utilization rates for 2009, 2010 and 2011 were 95%, 97% and 98%, respectively, compared to industry averages for the same periods of 79%, 89% and 88%, respectively. The utilization rates of our other assets are correlated with our rig utilization rates because the well drilling performed by our rigs creates demand for most of the other services we provide.

Significantly, we also have contractual arrangements with Chesapeake that provide additional revenue stability in the event of an industry downturn. Under our services agreement with Chesapeake, Chesapeake has guaranteed the utilization of the lesser of 75 of our drilling rigs or 80% of our operational drilling rig fleet at market-based rates. In addition, Chesapeake has guaranteed that each month it will ensure utilization of

 

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our operational hydraulic fracturing fleets, up to a maximum of 13 fleets, to complete a minimum aggregate number of fracturing stages equal to 25 stages per month for each fleet at market-based rates.

We currently conduct our business through five operating segments:

Drilling.    Nomac Drilling, L.L.C., our drilling subsidiary, provides premium land drilling and drilling-related services, including directional drilling, geosteering and mudlogging, for oil and natural gas exploration and development activities. As of March 31, 2012, we operated a fleet of 111 land drilling rigs, making us the fourth largest land driller operating in the U.S. according to RigData, an independent source of drilling activity information. To address Chesapeake’s needs for horizontal drilling in shale formations and other unconventional resource plays, we have expanded our areas of operation and improved the capability of our drilling rig fleet. We are in the process of building 12 new rigs that will utilize advanced electronic drilling technology, including 10 of our proprietary, fit-for-purpose PeakeRigs, which are scheduled to be delivered at a rate of approximately one rig per month through May 2013. We are also in the process of refurbishing three rigs in order to modernize and increase the capability of those rigs. For the year ended December 31, 2011, Chesapeake’s gross operated expenditures for drilling and drilling-related services were approximately $1.7 billion, and our revenues from this segment represented approximately 50% of such expenditures.

Hydraulic Fracturing.    Performance Technologies, L.L.C., our hydraulic fracturing subsidiary, provides hydraulic fracturing and other well stimulation services. We began hydraulic fracturing operations in the fourth quarter of 2011 with one hydraulic fracturing fleet and currently have four operational fleets with an aggregate of approximately 140,000 horsepower. We plan to have eight such fleets with approximately 315,000 horsepower in the aggregate operating by the end of 2012 and 12 such fleets with approximately 450,000 horsepower in the aggregate operating by the end of 2013. For the year ended December 31, 2011, Chesapeake’s gross operated expenditures for hydraulic fracturing services were approximately $3.5 billion, and our revenues from this segment represented less than 1% of such expenditures.

Oilfield Rentals.    Great Plains Oilfield Rental, L.L.C., our oilfield rentals subsidiary, provides a wide range of premium rental tools and services for land-based oil and natural gas drilling, completion and workover activities. We offer a full line of rental tools, including drill pipe, drill collars, tubing, blowout preventers, frac and mud tanks and also provide air drilling services and services associated with the transfer of fresh water to the well site. As our oilfield rentals segment generates our highest margins and we currently supply Chesapeake with a low percentage of its overall oilfield rentals requirements, this segment offers attractive expansion opportunities, including the purchase and subsequent rental of equipment used in pressure control, flowback and hydraulic fracturing services. For the year ended December 31, 2011, Chesapeake’s gross operated expenditures for oilfield rentals were approximately $1.3 billion, and our revenues from this segment represented approximately 19% of such expenditures.

Oilfield Trucking.    Hodges Trucking Company, L.L.C. and Oilfield Trucking Solutions, L.L.C., our oilfield trucking subsidiaries, provide rig relocation and logistics services and fluid hauling services. Our trucks move drilling rigs, crude oil, fluids and construction materials to and from the well site and also transport produced water from the well site. As of March 31, 2012, we owned a fleet of 227 rig relocation trucks, 57 cranes and forklifts used in the movement of drilling rigs and other heavy equipment and 157 fluid hauling trucks. Expansion opportunities for our oilfield trucking segment include expanding our assets, such as our crude hauling capabilities, and deploying our assets in new areas. For the year ended December 31, 2011, Chesapeake’s gross operated expenditures for rig relocation and logistics services were approximately $167.0 million, and our revenues from this segment represented approximately 77% of such expenditures. These amounts do not include

 

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Chesapeake’s expenditures for fluid hauling services, of which we currently provide only a small percentage.

Other Operations.    Compass Manufacturing, L.L.C., our manufacturing subsidiary, designs, engineers, fabricates, sells and installs natural gas compression units, accessories and equipment used in the production, treatment and processing of oil and natural gas. As of March 31, 2012, we had the capacity to manufacture up to 150 compressor units per quarter, or approximately 85,000 horsepower in the aggregate per quarter. Expansion opportunities for Compass include the manufacture of other types of oilfield equipment that are used in our oilfield rentals business. For the year ended December 31, 2011, Chesapeake’s gross operated expenditures for compressor purchases were approximately $87.5 million, and we provided Chesapeake with approximately 66% of its compressor manufacturing needs.

Our Competitive Strengths

We believe that we have the following competitive strengths:

Our relationship with Chesapeake.    For nearly eight years, Chesapeake, our founder and principal customer, has maintained the nation’s most active drilling program, based on rig count. For the years ended December 31, 2009, 2010 and 2011, Chesapeake drilled 1,212, 1,445 and 1,662 gross operated oil and natural gas wells, respectively, and made $5.2 billion, $7.9 billion and $13.3 billion, respectively, of gross operated drilling and completion expenditures. As of December 31, 2011, Chesapeake had total estimated net proved reserves of 18.8 tcfe, which includes approximately 545 mmbbls of liquids, and was operating 162 drilling rigs to develop its inventory of approximately 39,000 risked net drill sites. We anticipate that a significant portion of the demand for our services in future years will come from Chesapeake’s exploitation of this large backlog of drilling locations, approximately 20 years’ worth at current drilling levels.

The chart below shows the average number of rigs drilling for Chesapeake during 2009, 2010 and 2011 compared to its most active competitors.

 

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Source: RigData—The Land Rig Newsletter Biweekly Report (excludes operating rigs that are in the process of rigging up or mobilization).

 

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Looking forward, Chesapeake’s gross operated drilling and completion expenditure budgets for 2012 and 2013 are expected to be approximately $11.0 billion and $12.0 billion, respectively. Chesapeake’s industry-leading acreage position and active drilling program provide us with significant growth opportunities. Our relationship with Chesapeake, which gives us unique insights into our principal customer’s current and future oilfield services needs, positions us to operate efficiently, maintain industry-leading asset utilization and continue to improve our margins and creates incentives for Chesapeake to use our services.

Significant revenue growth opportunities.    Chesapeake’s current and future oilfield services needs provide us with significant growth opportunities. As shown in the table below, revenues from our hydraulic fracturing and oilfield rentals segments in 2011 represented less than 1% and approximately 19%, respectively, of Chesapeake’s gross operated expenditures for these services, which is well below our objective of providing up to two-thirds of Chesapeake’s overall expected need for these services.

 

Segment(1)

   2011 Revenues
(in millions)(2)
     Chesapeake’s 2011 Gross
Operated Expenditures

(in millions)
     As a Percentage
of Chesapeake’s
Gross Operated
Expenditures
 

Drilling

   $ 855       $ 1,725         50

Hydraulic Fracturing

   $ 13       $ 3,486         0

Oilfield Rentals

   $ 246       $ 1,266         19

 

(1) See Note 14 to our audited consolidated financial statements included elsewhere in this prospectus for additional information about our reportable segments.
(2) Drilling and oilfield rentals segment revenues include third-party revenues. Hydraulic fracturing includes ancillary support services.

In addition, within our drilling and oilfield trucking segments, we currently provide Chesapeake with a small percentage of its needs for drilling-related services and fluid hauling services, providing us with additional growth opportunities. We will also have the opportunity to increase the scope of our service offerings to Chesapeake and its partners and to grow with Chesapeake, whose drilling and completion expenditures have increased by an average of 27% year over year since 2006. We believe that Chesapeake’s oilfield services demand and its incentives to use our services will provide us with the opportunity to grow our business significantly with relatively low risk of over-expansion.

 

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Industry-leading asset utilization.    Chesapeake’s 20-year backlog of risked drilling locations, many of which are in unconventional liquids plays, provides us with a unique opportunity to keep our assets highly utilized for years to come. We believe that Chesapeake’s incentives to use our services, combined with our objective of matching our productive capacity to meet up to two-thirds of Chesapeake’s expected overall needs for our services, will allow us to maintain industry-leading asset utilization levels through industry cycles. Additionally, Chesapeake’s drilling activity levels over time have been more stable than those of its peers. For example, in the twelve-month period ended September 30, 2009, one of the most challenging periods in the recent history of our industry, the U.S. onshore industry rig count decreased by 1,308 rigs, or 50%, while Chesapeake’s operated rig count, which includes third-party rigs, decreased by only 53 rigs, or 34%. During that same period, Chesapeake’s utilization of our rigs increased by six rigs, from 71 to 77, or 8%. The utilization rates of our other assets are correlated with our rig utilization rates because the well drilling performed by our rigs creates demand for most of the other services we provide. The chart below shows our drilling rig utilization over the last four years as compared with the U.S. industry onshore average.

 

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Source: RigData and Nomac active rig counts.

Additionally, our services agreement with Chesapeake guarantees the utilization of a portion of our drilling rig and hydraulic fracturing fleets through October 2016, with an annual evergreen thereafter. While we believe the utilization of our assets will remain at a level significantly higher than the minimum utilization rates provided for in the services agreement, the guaranteed utilization provides us with downside protection in our traditionally cyclical industry.

 

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Enhanced operational efficiencies.    Our unique relationship with Chesapeake creates operational efficiencies that our competitors cannot replicate. We have access to the activity forecasts prepared by Chesapeake and we maintain close communications with Chesapeake regarding its service needs, allowing us to efficiently provide timely, tailored, “just-in-time” service to Chesapeake. As the graph below indicates, we drill wells for Chesapeake and its partners on average approximately 10% faster than our competitors do.

 

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Source: Chesapeake internal reports based on wells spudded in 2011.

Our ability to align our operations and forecasts with Chesapeake incentivizes it to use our services, provides us with cost savings and efficient deployment of capital and allows us to provide services at an overall cost that is attractive to Chesapeake and its partners. Our relationship with Chesapeake also provides us with the support of a large, well-known parent-sponsor which we believe benefits us in dealing with suppliers, lenders, capital providers and others that a similarly sized standalone service company could not replicate. Finally, we believe that Chesapeake’s workplace reputation, which was recently recognized on FORTUNE’s 100 Best Companies to Work For® list as the best among energy production companies, and our stable asset utilization levels have allowed us to build a well-trained, safe and efficient workforce of over 5,000 employees and to maintain a lower employee turnover rate compared to industry averages.

Diversified, high quality asset base.    Our modern and well maintained assets are capable of providing unique operational advantages to Chesapeake. A substantial majority of our drilling rig fleet has been newly fabricated or refurbished since 2001, and substantially all of our rigs have been updated with the equipment necessary for horizontal drilling in today’s unconventional resource plays. We expect to have an additional 30 of our proprietary, fit-for-purpose PeakeRigs operating in the next six years, which will utilize state-of-the-art technology to improve drilling efficiency and will be rated 1,000 horsepower or greater. We also have an initiative underway to repower our drilling rigs with dual fuel, diesel/natural gas (DNG) systems, which will reduce our customers’ costs through the utilization of natural gas during our rig operations. Our hydraulic fracturing assets are among the newest in the industry, with 100% of our fleet built in 2011 or later by manufacturers with strong reputations for producing durable equipment capable of withstanding the demanding conditions typically presented by unconventional reservoirs. Our oilfield rentals, oilfield trucking and natural gas compressor manufacturing assets are modern and well maintained. The quality of our asset base and our comprehensive maintenance program results in less downtime, lower operating costs and increased utilization of our

 

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assets, which is critical for drilling and hydraulic fracturing operations where assets are commonly utilized on a 24-hour per day, seven day per week basis.

Experienced management team.    We have an experienced and skilled management team which is led by our Chief Executive Officer, Jerry L. Winchester, who has over 30 years of industry experience, including 13 years of experience as the president and chief executive officer of Boots & Coots International Well Control, Inc. (“Boots & Coots”). Our management team, including Mr. Winchester, Cary D. Baetz, our Chief Financial Officer, James G. Minmier, President of Nomac Drilling, L.L.C., Zachary M. Graves, President of Thunder Oilfield Services, L.L.C., William R. Stanger, President of Performance Technologies, L.L.C., and Alan D. Lavenue, President of Compass Manufacturing, L.L.C., collectively has over a century of oilfield services experience with prominent oilfield service companies such as Halliburton Company, Boots & Coots, Helmerich & Payne, Inc., Schlumberger Limited, Precision Drilling Corporation, Bronco Drilling Company, Inc. and Exterran Holdings, Inc. The remainder of our management team is comprised of seasoned operating, financial and administrative executives with extensive experience in and knowledge of the oilfield services industry. Our management team has operated through numerous oilfield services cycles and provides us with valuable experience and a detailed understanding of customer requirements.

Our Business Strategy

Our goal is to maximize shareholder value by profitably building a leading oilfield services company through leveraging our relationship with Chesapeake, the most active driller of new oil and natural gas wells in the U.S., to achieve our objective of providing up to two-thirds of Chesapeake’s overall expected needs for our current and future services and maintain industry-leading utilization rates. We plan to pursue the following strategic objectives to achieve this goal.

Grow our asset base.    We intend to aggressively grow our asset base, particularly our hydraulic fracturing fleets, oilfield rental inventory and our drilling-related services, in order to achieve our objective of increasing our productive capacity to meet up to two-thirds of Chesapeake’s expected need for our services. We have placed substantial orders for additional new hydraulic fracturing units and expect to have eight fleets with approximately 315,000 horsepower in the aggregate operating by the end of 2012 and 12 fleets with approximately 450,000 horsepower in the aggregate operating by the end of 2013. Our drilling, hydraulic fracturing and oilfield rentals segments provide our highest margins and highest returns on invested capital relative to the other segments in which we operate. We are focused on increasing the revenues of these segments by growing our assets and expanding into the markets necessary to meet higher percentages of Chesapeake’s needs for these services, particularly the liquids-rich plays in which Chesapeake is now most active. During 2012 and 2013, we plan to make $1.1 billion to $1.2 billion of growth capital expenditures, in addition to amounts budgeted for the acquisition of presently leased rigs, and these expenditures will allow us to meet a greater percentage of Chesapeake’s needs and solidify our position as one of the largest U.S. onshore oilfield services companies.

Focus on full utilization of our assets.    Our oilfield service assets have traditionally maintained high utilization rates. For example, the utilization of our drilling rigs has averaged between approximately 95% and 99% since 2008. The utilization rates of our other assets are directly correlated with our rig utilization rates because the well drilling performed by our rigs creates demand for most of the other services we provide. Our industry-leading asset utilization rates result from our strategy of growing in tandem with Chesapeake and serving as a substantial provider of oilfield services to Chesapeake and its partners. We plan to maintain our industry-leading utilization rates as we continue to grow by growing our productive capacity to meet up to two-thirds of Chesapeake’s overall expected need for our services. We believe this strategy, combined with

 

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Chesapeake’s incentives to use our services, will continue to result in high utilization rates for our assets throughout industry cycles.

Focus on improving margins.    We plan to continue to improve our margins by leveraging our relationship with Chesapeake to decrease costs and make our business more efficient. Our relationship with Chesapeake enables us to operate more efficiently than our competitors by providing us with exclusive access to data that allows us to align our operations and projections with those of Chesapeake, to efficiently provide Chesapeake with timely, tailored, “just-in-time” services and to anticipate and quickly react to industry trends. As a result, our management team can focus its efforts on delivering efficient, high-quality services to Chesapeake and its partners rather than on marketing our services and managing through the cyclicality of oilfield activity and commodity prices. Additionally, we plan to continue to evolve our product and service offerings to include a larger percentage of higher margin offerings. We also believe that our new management team, which is exclusively dedicated to our operations and collectively has over a century of experience in the oilfield services industry, will enable us to better capitalize on existing efficiencies and identify further opportunities to maximize our margins. For example, since July 2011, our new management team has increased the gross margins in our drilling segment through various cost saving initiatives by approximately 20%, while at the same time improving our safety and productivity metrics.

Capitalize on opportunities to provide additional services.    As the driller of a substantial majority of Chesapeake’s wells, we play a central role in the planning and execution of Chesapeake’s drilling program. As a result of this role, we are uniquely positioned to cross-sell our other service offerings to Chesapeake, observe the service offerings of other third-party service providers that are present at the well site and evaluate expansion opportunities. We plan to use this role to focus our growth on high margin product and services offerings. While we already provide Chesapeake with approximately two-thirds of its drilling rig needs, we plan to increase the percentage of drilling-related services that we provide, such as directional drilling, mud logging and geosteering. In our hydraulic fracturing segment, we believe that expansion opportunities exist not only through expanding our fleets but also by vertically integrating our operations through the integration of sand reserves, sand processing operations and railcar, truck and other logistics assets. We also plan to continue to grow our oilfield rentals segment, where our inventory of tools and equipment can be expanded to include additional drilling and completion rental tools. We have a significant growth capital expenditure budget of between $1.1 billion and $1.2 billion over the next two years with which to develop such business lines. These amounts are in addition to amounts budgeted for the acquisition of presently leased rigs. We believe that targeting the development of these high margin product and services offerings through geographic expansion, vertical integration and asset additions will provide us with a greater return on our investment in our assets and cash flows for future growth.

Continued focus on safety.    Our relationship with Chesapeake provides us with enhanced utilization across industry cycles, which in turn reduces employee turnover, increases safety and drives superior results. In addition, the continuity of working relationships between our employees and Chesapeake provides for greater communication and data sharing at our drill sites, which we believe results in safer working conditions for employees. We are focused on hiring, training and retaining high-quality employees. As a result of our strong emphasis on training and safety protocols for our employees, we believe we have a superior safety record and reputation. We have a strong and improving Total Recordable Incidence Rate (TRIR) safety record even as our employee base has more than doubled over the past two years. From 2009 to 2011, our TRIR dropped by approximately 36%. In addition, all of our field-based employees are eligible to receive incentive pay based on satisfying safety standards, which we believe motivates them to continually maintain quality and safety.

 

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Our Operating Segments

Drilling Segment

Drilling rig fleet.    Our drilling segment is operated through our wholly owned subsidiary, Nomac Drilling, L.L.C., and provides premium land drilling and drilling-related services, including directional drilling, geosteering and mudlogging, for oil and natural gas exploration and development activities. As of March 31, 2012, we operated a fleet of 111 operating land drilling rigs, making us the fourth largest land driller operating in the U.S. according to RigData. Our drilling rigs have depth ratings between 3,000 and 25,000 feet and horsepower ratings, which are based on the horsepower of the drawworks of the rigs, from 450 to 2,000. The following table sets forth the location of the land drilling rigs that we operated at March 31, 2012:

 

Resource Play

   Rig
Count
 

Anadarko Basin

     47   

Marcellus Shale

     23   

Eagle Ford Shale

     16   

Williston Basin

     10   

Barnett Shale

     4   

Haynesville/Bossier Shales

     6   

Utica Shale

     5   
  

 

 

 

Total

     111   

As of March 31, 2011, we had 17 drilling rigs, all of which are leased from CEF, that were idle, or “warm stacked,” or that had been placed in storage, or “cold stacked,” due to low demand for drilling rigs with their specifications. Our cold stacked rigs were generally designed for vertical drilling in conventional reservoirs and are not expected to be returned to service under current market conditions. Among our inactive drilling rigs are three rigs that are currently being refurbished, and two rigs that are being used in our training program.

A primary competitive advantage of our drilling segment is our relationship with Chesapeake, which is the most active driller of new wells in the U.S., based on rig count. Since 2000, Chesapeake has built the largest combined inventories of onshore leasehold (15.3 million net acres) and 3-D seismic (30.8 million acres) in the U.S. Chesapeake has also accumulated the largest inventory of U.S. natural gas shale play leasehold (2.2 million net acres) and now owns leading positions in 11 of what it believes are the top 15 liquids-rich plays in the U.S. As of March 31, 2012, Chesapeake was operating 162 drilling rigs, 100 of which were our rigs, to further develop its inventory. In the past, this key relationship has provided us with greater operational stability than our competitors and we expect that it will do so in the future. The following table sets forth historical information regarding utilization of our land drilling rig fleet and industry utilization rates according to Rig Data:

 

     December 31,  
     2009     2010     2011  

Average number of operating rigs for the period

     79        83        104   

Average utilization rate

     95     97     98

Average industry utilization rate

     79     89     88

Drilling rig specifications.    A drilling rig consists of engines, a hoisting system, a rotating system, pumps and related equipment to circulate drilling fluid, blowout preventers and related equipment.

Diesel or gas engines are typically the main power sources for a drilling rig. Power requirements for drilling jobs may vary considerably, but most drilling rigs employ two or more engines to operate the

 

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drilling rig and the ancillary equipment, which generate between 2,000 and 4,000 horsepower, depending on well depth and rig design. Most drilling rigs capable of drilling in deep formations, involving depths greater than 15,000 feet, use diesel-electric power units to generate and deliver electric current through cables to electrical switch gears, then to direct-current electric motors attached to the equipment in the hoisting, rotating and circulating systems.

Drilling rigs use long strings of drill pipe and drill collars to drill wells. Drilling rigs are also used to set heavy strings of large-diameter pipe, or casing, inside the borehole. Because the total weight of the drill string and the casing can exceed 500,000 pounds, drilling rigs require significant hoisting and braking capacities. Generally, a drilling rig’s hoisting system is made up of a mast, or derrick, a drilling line, a traveling block and hook assembly and ancillary equipment that attaches to the rotating system, a mechanism known as the drawworks. The drawworks mechanism consists of a revolving drum, around which the drilling line is wound, and a series of shafts, clutches and chain and gear drives for generating speed changes and reverse motion. The drawworks also houses the main brake, which has the capacity to stop and sustain the weights used in the drilling process. When heavy loads are being lowered, a hydromatic or electric auxiliary brake assists the main brake to absorb the great amount of energy developed by the mass of the traveling block, hook assembly, drill pipe, drill collars and drill bit or casing being lowered into the well.

Modern rotating equipment, from top to bottom, consists of a top drive, drill pipe, drill collars and the drill bit. We refer to the equipment between the top drive and the drill bit as the drill stem. The top drive sustains the weight of the drill stem, rotates the drill stem and provides a passageway for circulating drilling fluid into the top of the drill string. Drilling fluid enters the top drive through a hose, called the rotary hose. The drill pipe and drill collars are both steel tubes that, when rotated, rotate the drill bit and also allow a conduit to the drill bit through which drilling fluid can be pumped. Drill pipe, sometimes called drill string, comes in 30-foot sections, or joints, with threaded sections on each end. Drill collars are heavier than drill pipe and are also threaded on the ends. Collars are used on the bottom of the drill stem to apply weight to the drilling bit. At the end of the drill stem is the bit, which chews up the formation rock and dislodges it so that drilling fluid can circulate the fragmented material back up to the surface where the circulating system filters it out of the fluid.

Drilling fluid, often called mud, is a mixture of clays, chemicals and water or oil, which is carefully formulated for the particular well being drilled. Bulk storage of drilling fluid materials, the pumps and the mud-mixing equipment are placed at the start of the circulating system. Working mud pits and reserve storage are at the other end of the system. Between these two points the circulating system includes auxiliary equipment for drilling fluid maintenance and equipment for well pressure control. Within the system, the drilling mud is typically routed from the mud pits to the mud pump and from the mud pump through a standpipe and the rotary hose to the drill stem. The drilling mud travels down the drill stem to the bit, up the annular space between the drill stem and the borehole and through the blowout preventer stack to the return flow line. It then travels to a shale shaker for removal of rock cuttings, and then back to the mud pits, which are usually steel tanks. The rock cuttings are deposited into steel cuttings bins or earthen excavations called reserve pits and properly disposed of at the conclusion of the drilling process.

In a continuing effort to improve our drilling rig fleet, as of March 31, 2012, we had installed top drives on 107 rigs, or approximately 97% of our operating fleet and had installed iron roughnecks on 40 rigs. We plan to install top drives and iron roughnecks on all capable rigs. These upgrades provide our drilling rigs with more varied capabilities for drilling in unconventional plays, and they also improve our efficiency and safety. Top drives provide maximum torque and rotational control, improved well control and better hole conditioning. In horizontal drilling, operators can utilize top drives to reach formations that may not be accessible with conventional rotary drilling. An iron roughneck is a remotely operated pipe handling feature on the rig floor, which is used to help reduce the occurrence of repetitive motion

 

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injuries and decrease drill pipe tripping time. Several of our rigs accommodate skidding or walking systems. These walking systems increase efficiency by allowing multiple wells to be drilled on the same pad site and permitting the drilling rig to move between wells while drill pipe remains in the derrick, thus reducing move times and costs. We have installed mechanized catwalks on 23 of our rigs. A mechanized catwalk is a tubular handling feature used to raise drill pipe, drill collars, casing and other necessary items to the drilling rig floor. It reduces tubular transfer time, thereby increasing efficiency and decreasing operator costs for handling casing.

We have also begun a new build program that will add 12 new rigs that will utilize advanced electronic drilling technology, including 10 of our proprietary, fit-for-purpose PeakeRigs, which are scheduled to be delivered at a rate of approximately one rig per month through May 2013. These rigs will utilize state-of-the-art A/C power and control systems to improve drilling efficiency, include certain features to decrease well-to-well mobilization times and provide modern working environments, including joystick controls, touch-screen monitors and climate-controlled drillers’ cabins. All new build rigs will include top drives, iron roughnecks, walking systems and mechanized catwalks. We expect to have an additional 30 of our proprietary, fit-for-purpose PeakeRigs operating in the next six years, which will utilize state-of-the-art technology to improve drilling efficiency and will be rated 1,000 horsepower or greater.

There are numerous factors that differentiate drilling rigs, including their power generation systems and their drilling depth capabilities. The actual drilling depth capability of a rig may be less than or more than its rated depth capability due to numerous factors, including the size, weight and amount of the drill pipe on the rig. The intended well depth and the drill site conditions determine the amount of drill pipe and other equipment needed to drill a well. Generally, land rigs operate with crews of five to six persons working at any one time.

In addition to the various upgrades we have made to our drilling rigs, we also have ancillary assets and personnel to maximize the quality of our drilling services. Nomac’s wholly owned subsidiary, Nomac Services, L.L.C., provides integrated directional drilling, measurement while drilling (MWD), well bore planning, geosteering and mud logging services in both conventional and horizontal applications to maximize drilling efficiencies and lower costs.

We believe that our operating drilling rigs and other related equipment are in good operating condition. Our employees perform scheduled maintenance and minor repair work on our drilling rigs. Historically, we have relied on various oilfield service companies for major repair work and overhaul of our drilling equipment. We lease a 41,000 square foot machine shop in Oklahoma City, which allows us to refurbish and repair our rigs and equipment in-house. In the event of major breakdowns or mechanical problems, our rigs could be subject to significant idle time and a resulting loss of revenue if the necessary repair services are not immediately available.

As of March 31, 2012, we owned a fleet of 227 trucks and related oilfield trucking equipment, including 57 cranes and forklifts, which we use to transport our drilling rigs to and from drilling sites. By owning such equipment, we reduce the overall cost of rig moves and reduce downtime between rig moves. For more information concerning our rig relocation equipment, please see “—Oilfield Trucking Segment” below.

Drilling Customers and Contracts.    Chesapeake and its partners are our largest customers, representing 93% of our drilling revenues in the year ended December 31, 2011. We typically contract with Chesapeake on a well by well basis pursuant to a modified IADC daywork drilling contract for our drilling services. However, we recently entered into two-year term contracts with Chesapeake with regard to 10 of the drilling rigs coming out of our new build program. As of March 31, 2012, we had 10 drilling rigs operating in the Williston and Marcellus basins on term contracts with non-Chesapeake

 

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operators. As our contracts expire with non-Chesapeake parties, we expect to enter into new contracts with Chesapeake to supply their drilling needs with those rigs. Contract terms generally depend on the complexity and risk of operations, the on-site drilling conditions, the type of equipment used and the anticipated duration of the work to be performed. We typically enter into drilling contracts that provide for compensation on a daywork basis and that have market-based pricing, including with Chesapeake. We have entered into drilling contracts that provide for compensation on a footage basis in the past but do not currently intend to enter into footage contracts in the future. We have not historically entered into turnkey contracts. We may decide to enter into footage or turnkey contracts in the future.

Currently, all of our drilling contracts are daywork contracts. A daywork contract generally provides for a basic rate per day when drilling (the dayrate for our providing a rig and crew) and for lower rates when the rig is moving, or when drilling operations are interrupted or restricted by equipment breakdowns, adverse weather conditions or other conditions beyond our control. In addition, daywork contracts may provide for a lump-sum fee for the mobilization and demobilization of the rig, which in most cases approximates our incurred costs. Daywork drilling contracts are beneficial in that the customer bears a large portion of the out-of-pocket drilling costs and we generally bear no part of the usual risks associated with drilling, such as time delays and unanticipated costs. A daywork contract differs from a footage contract (in which the drilling contractor is paid on the basis of a rate per foot drilled) and a turnkey contract (in which the drilling contractor is paid for drilling a well to a specified depth for a fixed price). We expect that all of our future contracts with Chesapeake and third parties will be daywork contracts.

Hydraulic Fracturing Segment

Hydraulic fracturing development.    Our hydraulic fracturing segment is operated through our wholly owned subsidiary, Performance Technologies, L.L.C., and provides high-pressure hydraulic fracturing (or frac) services and other well stimulation services to Chesapeake. Fracturing services are performed to enhance the production of oil and natural gas from formations having low permeability such that the natural flow of hydrocarbons to the surface is restricted. We have gathered significant expertise in the fracturing of multi-stage horizontal natural gas and liquids-rich wells in shale and other unconventional geological formations.

Currently, we operate four hydraulic fracturing fleets with an aggregate of approximately 140,000 horsepower for Chesapeake. We plan to have eight such fleets with approximately 315,000 horsepower in the aggregate operating by the end of 2012 and 12 such fleets with approximately 450,000 horsepower in the aggregate operating by the end of 2013. We contemplate that we will make approximately $227.7 million of capital expenditures for our hydraulic fracturing segment for the year ending December 31, 2012.

Our initial operations have been focused in western Oklahoma. We plan to expand the focus of our operations in areas of the U.S. in which there are significant onshore developments requiring the application of advanced completion techniques where companies, including Chesapeake, are actively developing and producing oil and natural gas. We believe that we will have significant opportunities for further expansion beyond four crews presently operating in Mid-Continent area. These areas would include the Eagle Ford, Utica and Marcellus, which are all shale formations that typically require hydraulic fracturing in order to be productive.

Hydraulic fracturing process.    The fracturing process consists of pumping a fracturing fluid into a well at sufficient pressure to fracture the formation. Materials known as proppants, primarily sand or sand coated with resin, are suspended in the fracturing fluid and are pumped into the fracture to prop it open. The fracturing fluid is designed to “break,” or lose viscosity, and be forced out of the formation by its pressure, leaving the proppants suspended in the fractures.

 

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Companies offering fracturing services typically own and operate fleets of mobile, high-pressure pumping systems and other heavy equipment. We refer to these pumping systems, each of which consists of a high pressure reciprocating pump, diesel engine, transmission and various hoses, valves, tanks and other supporting equipment, all typically mounted to a flat-bed trailer, as “fracturing units.” The group of fracturing units, other equipment and vehicles necessary to perform a typical fracturing job is referred to as a “fleet.” Each fleet typically consists of eight to 20 fracturing units, two or more blenders (one used as a backup), which blend the proppant and chemicals into the fracturing fluid, sand chiefs, which are large containers used to store sand on location, various vehicles used to transport sand, chemicals, gels and other materials, various service trucks and a monitoring van equipped with monitoring equipment and computers that control the fracturing process. The personnel assigned to each fleet are commonly referred to as a “crew.”

An important element of fracturing services is determining the proper fracturing fluid, proppants and injection program to maximize results. We employ field engineering personnel to provide technical evaluation and job design recommendations for customers as an integral element of our fracturing service. Technological developments in the industry over the past several years have focused on proppant density control, liquid gel concentrate capabilities, computer design and monitoring of jobs and cleanup properties for fracturing fluids.

Proppant and chemical supply.    The proppant we use most frequently is raw sand. A reliable source of raw sand and the ability to deliver it to job sites quickly and efficiently are crucial to the success of our hydraulic fracturing business. This is particularly significant during periods in which there are shortages of sand, such as in late 2008. As activity in our industry has increased, demand for and prices of sand have increased significantly. We are in the process of integrating reserves of raw sand and establishing our own mining and processing facilities, which we believe will provide us with a stable source of proppants and reduce our exposure to potential shortages. We have entered into non-metallic mineral mining leases at potential sand mining sites consisting of approximately 1,700 total acres of sand reserves in Wisconsin. We have also entered into an agreement with a dedicated hydraulic fracturing sand carrier to ensure adequate truck transportation services for hauling our hydraulic fracturing sand from our regional distribution points to the well site, and we have entered into rail car leases for the bulk transportation of hydraulic fracturing sand by rail from the mine origins to our regional distribution hubs.

We purchase the fracturing fluid used in our hydraulic fracturing activities from third-party suppliers. The suppliers are responsible for storage, handling and compatibility of the chemicals used in the fracturing fluid. We also require our suppliers to adhere to strict environmental and quality standards and to maintain minimum inventory levels at regional hubs, thus ensuring adequate supply for our hydraulic fracturing operations.

Hydraulic fracturing customers and contracts.    All of our hydraulic fracturing services are currently performed for Chesapeake and we anticipate that this will continue to be the case in the foreseeable future. We contract with Chesapeake pursuant to a master services agreement that specifies payment terms, audit rights and insurance requirements and allocates certain operational risks through indemnity and similar provisions. We supplement these agreements for each engagement with a bid proposal, subject to customer acceptance, containing such things as the estimated number of fracturing stages to be performed, pricing, quantities of products expected to be needed, and the number, horsepower and pressure ratings of the hydraulic fracturing fleets to be used. We are generally compensated based on the number of fracturing stages we complete and pricing is market based. See “Certain Relationships and Related Party Transactions—Master Services Agreement” and “Certain Relationships and Related Party Transactions—Services Agreement.”

 

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Oilfield Rentals Segment

Our oilfield rentals segment is operated through our wholly owned subsidiary, Great Plains Oilfield Rental, L.L.C., and provides a wide range of premium rental tools and services for land-based oil and natural gas drilling, completion and workover activities. Our rental equipment allows Chesapeake to have access to inventories of tools and other equipment without the cost of purchasing, maintaining or storing that equipment in its own inventory. As of March 31, 2012, our rental tool inventory and services included:

 

  Ÿ  

large diameter drill pipe, heavy weight drill pipe, high torque drill pipe, drill collars, tubing and other required accessories;

 

  Ÿ  

pressure control equipment, such as blowout preventers, high pressure valves, choke and kill manifolds and test pumps;

 

  Ÿ  

water transfer services;

 

  Ÿ  

air drilling services; and

 

  Ÿ  

frac tanks and mud tanks.

We have various sizes of tubulars and related handling tools, providing a wide range of equipment for drilling at a wide range of well depths and conditions. In response to the growth in directional drilling, we have expanded our inventory of premium, high torque drill pipe, which also provides operators with the technical characteristics demanded by deeper wells and wells expected to encounter harsh geological conditions. Generally, our customers rent drill pipe for use in the lateral section of a horizontal well. Our water transfer services involve providing water to be used in hydraulic fracturing during the completion of a well. These rental tools and related services are marketed through our internal sales force. The majority of our equipment and tools are rented to our customers on a per day basis and are returned after use.

Oilfield Trucking Segment

Our oilfield trucking segment provides rig relocation and logistics services as well as fluid hauling services to Chesapeake and other E&P companies.

Drilling rig relocation and logistics.    Our drilling rig relocation and logistics services are operated through our wholly owned subsidiary, Hodges Trucking Company, L.L.C., and provide heavy-duty trucks and equipment used in the movement of land drilling rigs. Hodges has been operating in the oilfield trucking industry for more than 75 years. Our fleet includes three-axle slick-back trucks, three- and four-axle winch trucks, gin-pole trucks, tandem trucks, trailers and forklifts. As of March 31, 2012, we owned a fleet of 227 rig relocation trucks, as well as 57 cranes and forklifts used in the movement of drilling rigs and other heavy equipment. Our trucks and equipment are designed and equipped to meet a variety of terrain and climate conditions. We have a state-of-the-art maintenance and fabrication facility staffed with certified personnel, and we have also created a standardized parts inventory, allowing us to fix problems in the field, minimizing downtime and cost.

Fluid Hauling.    Our fluid hauling services are operated through our wholly owned subsidiary, Oilfield Trucking Solutions, L.L.C., and provide heavy- and medium-duty trucks used in connection with the movement of fluids to and from well sites. We operate our fluid hauling services from four facilities located in West Virginia, Pennsylvania and Texas. Fluid hauling trucks are utilized in connection with drilling, completion and workover projects, which tend to use large amounts of various fluids. Each fluid service truck is equipped to pump fluids from or into wells, pits, tanks and other storage facilities. The majority of our fluid hauling trucks are also used to transport water to fill frac tanks on well locations, including frac tanks provided by us through our oilfield rentals segment and third parties, to transport

 

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produced water to disposal wells or facilities and to transport drilling and completion fluids to and from well locations. We also own trucks that are used in the hauling of crude oil. As of March 31, 2012, we owned a fleet of 157 fluid hauling trucks with a fluid hauling capacity of up to 130 barrels of water and 200 barrels of crude oil. We expect to significantly expand our crude hauling capabilities in the next three years, adding 90 crude hauling trucks with a crude hauling capacity of up to 200 barrels of crude oil per truck and an aggregate of 18,000 total barrels of crude oil.

Other Operations

Our other operations segment primarily consists of our natural gas compressor manufacturing operations and is operated through our wholly owned subsidiary, Compass Manufacturing, L.L.C. We sell large and small natural gas compressor packages and related production equipment used in the production, gathering and transportation of natural gas. Natural gas compression is a mechanical process whereby the pressure of a volume of natural gas is increased to a desired higher pressure for transportation from one point to another, and is essential to the production and transportation of natural gas. Compression is typically required several times during the natural gas production and transportation cycle, including: (a) at the wellhead; (b) throughout gathering and distribution systems; (c) into and out of processing and storage facilities; and (d) along intrastate and interstate pipelines. We design, engineer, fabricate, sell and install natural gas compression units and accessories and equipment used in the production, treating and processing of natural gas and crude oil. As of March 31, 2012, we had the capacity to manufacture up to 150 compressor units per quarter, or a maximum of 85,000 horsepower in the aggregate per quarter. We recently expanded our manufacturing facility, adding approximately 39,000 square feet, bringing the total square footage to 134,000, which has allowed us to double our compressor unit manufacturing capacity in 2012 from our capacity capabilities in most of 2011.

Customers and Competition

The markets in which we operate are highly competitive. Because substantially all of our operations are performed for Chesapeake and its partners, we do not currently face significant competition for our services. We are, however, affected by competition, as Chesapeake pays us market-based rates for the services and products we provide. To the extent that competitive conditions increase and prices for the services and products we provide decrease, we may be required to charge Chesapeake less for such products and services.

In the future, we may face competition to the extent we decide to diversify our customer base. We currently anticipate that our competitors in each of our operating segments and other operations would include:

 

  Ÿ  

Drilling—Helmerich & Payne, Inc., Patterson-UTI Energy, Inc., Trinidad Drilling Ltd., Nabors Industries Ltd., Pioneer Drilling Company, Precision Drilling Corporation and a significant number of other competitors with national, regional or local rig operations;

 

  Ÿ  

Hydraulic Fracturing—Halliburton Company, Schlumberger Limited, Baker Hughes Incorporated, FTS International, Inc. and several other competitors with national, regional or local hydraulic fracturing operations;

 

  Ÿ  

Oilfield Rentals—Key Energy Services, Inc., RPC, Inc., Oil States International, Inc., Baker Oil Tools, Weatherford International, Basic Energy Services, Superior Energy Services, Quail Tools (owned by Parker Drilling Company), Knight Oil Tools and several other competitors with national, regional or local tool rental operations;

 

  Ÿ  

Oilfield Trucking—Basic Energy Services, Inc., Key Energy Services, Inc., Superior Energy Services and several other competitors with national, regional or local trucking operations; and

 

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  Ÿ  

Other Operations—Cameron International Corporation, Exterran Partners, L.P. and several other competitors with national, regional or local natural gas compressor manufacturing operations.

Suppliers

We purchase a wide variety of raw materials, parts and components that are made by other manufacturers and suppliers for our use. We are not dependent on any single source of supply for those parts, supplies or materials.

For our drilling rigs, we generally purchase individual components from reputable original equipment manufacturers and then assemble and commission the rigs ourselves at an internal facility, which we believe results in cost savings and higher quality. Occasionally, we may purchase a full rig package from an outside vendor if such package provides technical and commercial advantages over our in-house approach.

We have purchased the majority of our hydraulic fracturing units from FTS International and United Engines. We currently have an agreement with FTS International for a delivery of 80 additional pumping units in 2012. We purchase the raw materials we use in our hydraulic fracturing operations, such as sand, chemicals and diesel fuel, from a variety of suppliers throughout the U.S.

To date, we have generally been able to obtain on a timely basis the equipment, parts and supplies necessary to support our operations. Where we currently source materials from one supplier, we believe that we will be able to make satisfactory alternative arrangements in the event of interruption of supply. However, given the limited number of suppliers of certain of our raw materials, we may not always be able to make alternative arrangements should one of our supplier’s fail to deliver or timely deliver our materials.

Related Party Agreements

We are a party to a master services agreement and services agreement with Chesapeake. The master services agreement governs the performance of services and/or the supply of materials or equipment to Chesapeake, the specifics of which are handled under separate field tickets or purchase or work orders. Under the services agreement, which is subject to the terms of the master services agreement, Chesapeake has agreed to operate a minimum number of our rigs and to utilize our hydraulic fracturing equipment for a minimum number of fracturing stages per month. The field tickets and work and purchase orders with Chesapeake are substantially similar to those in prevailing industry contracts, specifically as they relate to pricing, liabilities and payment terms.

In addition to the foregoing agreements, we and Chesapeake have entered into various other agreements, including an administrative services agreement, that we entered into in the context of an affiliated relationship.

For a more comprehensive discussion concerning the master services agreement, the services agreement and the other agreements that we have entered into, or anticipate entering into, with Chesapeake and certain of its affiliates, please see “Certain Relationships and Related Party Transactions.”

 

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Employees

At every level of our operations, our employees are critical to our success and committed to operational excellence. Our senior management team has extensive experience building, acquiring and managing oilfield service and other assets. Their focus is on optimizing our business and expanding operations. On an operations level, our supervisory and field personnel are empowered with the training, tools and confidence required to succeed in their jobs.

As of March 31, 2012, we employed approximately 5,500 people. None of these employees are covered by collective bargaining agreements and we and Chesapeake consider our relationships with our employees to be good.

Properties

We conduct our operations out of a number of field offices, yards, shops, terminals and other facilities located in North Dakota, Oklahoma, Ohio, Pennsylvania, Texas and West Virginia. Each of these facilities is leased from Chesapeake pursuant to our facilities lease agreement or from a third party. We do not believe that any one of these facilities is individually material to our operations.

Risk Management and Insurance

The oilfield services business involves a variety of operating risks, including the risk of fire, explosions, blow-outs, pipe failure, abnormally pressured formations and environmental hazards such as oil spills, natural gas leaks, ruptures or discharges of toxic gases. If any of these should occur, we could incur legal defense costs and could suffer substantial losses due to injury or loss of life, severe damage to or destruction of property, natural resources and equipment, pollution or other environmental damage, clean-up responsibilities, regulatory investigation and penalties, and suspension of operations. Our horizontal and deep drilling activities involve greater risk of mechanical problems than vertical and shallow drilling operations.

We maintain policies of insurance that we believe are customary in the industry with customary deductibles or self-insured retentions and there are no assurances that this insurance will be adequate to cover all losses or exposure to liability. We carry a $425.0 million comprehensive general liability umbrella policy and a $150.0 million pollution liability policy. We provide workers’ compensation insurance coverage to employees in all states in which we operate. While we believe these policies are customary in the industry, they do not provide complete coverage against all operating risks. In addition, our insurance does not cover penalties or fines that may be assessed by a governmental authority. A loss not fully covered by insurance could have a material adverse effect on our financial position, results of operations and cash flows. Moreover, these policies also cover properties and operations of Chesapeake unrelated to our properties or operations. To the extent proceeds from such policies are used to cover losses in Chesapeake’s other operations, such coverage may not be available to cover losses relating to our operations. The insurance coverage that we maintain may not be sufficient to cover every claim made against us or may not be commercially available for purchase in the future. Also, in the past, insurance rates have been subject to wide fluctuation, and changes in coverage could result in less coverage, increases in cost or higher deductibles and self-insured retentions.

Our master services agreement with Chesapeake includes certain indemnification provisions for losses resulting from operations. Generally, we take responsibility for our own people and property while Chesapeake takes responsibility for its own people, property and liabilities related to the well and subsurface operations, regardless of either party’s negligence. For example, our master services

 

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agreement provides that Chesapeake assume liability for (a) damage to the hole, including the cost to re-drill; (b) damages or claims arising from loss of control of a well or a blowout; (c) damage to the reservoir, geological formation or underground strata; (d) damages arising from the use of radioactive tools or any contamination resulting therefrom; (e) damages arising from pollution or contamination (other than surface spills attributable to our negligence); (f) damages arising from damage to, or escape of any substance from, any pipeline, vessel or storage or production facility; and (g) allegations of subsurface trespass.

In general, any material limitations on indemnifications to us from Chesapeake in support of this allocation of responsibility arise only by applicable state laws or public policy. Certain states such as Texas, Louisiana, Wyoming, and New Mexico have enacted oil and natural gas specific statutes that void any indemnity agreement that attempts to relieve a party from liability resulting from its own negligence. These statutes can void the allocation of liability agreed to in a contract. We believe, however, that our master services agreement is structured so that any limitations on the indemnification obligations of Chesapeake should not have a material impact on the terms of the agreement.

Safety and Maintenance

Our business involves the operation of heavy and powerful equipment which can result in serious injuries to our employees and third parties and/or substantial damage to property and/or environmental harm. We have comprehensive environmental, health, and safety (EHS) and training programs designed to reduce accidents in the workplace and improve the efficiency of our operations. In addition, our largest customer, Chesapeake, places great emphasis on EHS and quality management programs of its contractors. We believe that these factors will gain further importance in the future. We have directed substantial resources toward employee EHS and quality management training programs as well as our employee review process and have benefitted from steadily decreasing incident frequencies and severity.

Regulation of Operations

We operate under the jurisdiction of a number of regulatory bodies that regulate worker safety standards, the handling of hazardous materials, the transportation of explosives, the protection of the environment and driving standards of operation. Regulations concerning equipment certification create an ongoing need for regular maintenance that is incorporated into our daily operating procedures. The oil and natural gas industry is subject to environmental regulation pursuant to local, state and federal legislation.

Among the services we provide, we operate as a motor carrier and therefore are subject to regulation by the U.S. Department of Transportation and by various state agencies. These regulatory authorities exercise broad powers, governing activities such as the authorization to engage in motor carrier operations and regulatory safety, financial reporting and certain mergers, consolidations and acquisitions. There are additional regulations specifically relating to the trucking industry, including testing and specification of equipment and product handling requirements. The trucking industry is subject to possible regulatory and legislative changes that may affect the economics of the industry by requiring changes in operating practices or by changing the demand for common or contract carrier services or the cost of providing truckload services. Some of these possible changes include increasingly stringent environmental regulations, changes in the hours of service regulations that govern the amount of time a driver may drive in any specific period, onboard black box recorder devices or limits on vehicle weight and size.

 

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Interstate motor carrier operations are subject to safety requirements prescribed by the U.S. Department of Transportation. To a large degree, intrastate motor carrier operations are subject to safety regulations that mirror federal regulations. Such matters as weight and dimension of equipment are also subject to federal and state regulations. Department of Transportation regulations mandate drug testing of drivers.

From time to time, various legislative proposals are introduced, including proposals to increase federal, state, or local taxes, including taxes on motor fuels, which may increase our costs or adversely impact the recruitment of drivers. We cannot predict whether, or in what form, any increase in such taxes applicable to us will be enacted.

Environmental Matters

Our operations are subject to various federal, state and local environmental, health and safety laws and regulations pertaining to the release, emission or discharge of materials into the environment, the generation, storage, transportation, handling and disposal of materials (including solid and hazardous wastes), the safety of employees, or otherwise relating to pollution, preservation, remediation or protection of human health and safety, natural resources, wildlife or the environment. Federal environmental, health and safety laws that govern our operations include the Comprehensive Environmental Response, Compensation, and Liability Act, or CERCLA, the Clean Water Act, the Safe Drinking Water Act, the Clean Air Act, the Resource Conservation and Recovery Act, or RCRA, the Endangered Species Act, the Migratory Bird Treaty Act, and the regulations promulgated pursuant to such laws.

Federal laws, including CERCLA and analogous state laws, impose joint and several liability, without regard to fault or legality of the original conduct, on classes of persons who are considered responsible for releases of a hazardous substance into the environment. These persons include the current or former owner or operator of the site where the release occurred and persons that generated, disposed of or arranged for the disposal of hazardous substances at the site. CERCLA and analogous state laws also authorize the EPA, state environmental agencies and, in some cases, third parties to take action to mitigate, prevent or respond to threats to human health or the environment and to seek to recover the costs of such actions from responsible classes of persons.

Other federal and state laws, in particular RCRA, regulate hazardous and non-hazardous wastes. In the course of our operations, we generate petroleum hydrocarbon wastes and other maintenance wastes. We believe we are in material compliance with all regulations regarding the handling of wastes from our operations. Some of our wastes are not currently classified as hazardous wastes, but may in the future be designated as hazardous wastes and may thus become subject to more rigorous and costly compliance and disposal requirements. Such additional regulation could have a material adverse effect on our business.

We lease a number of properties that have been used as service yards in support of oil and natural gas exploration and production activities. Although we utilized operating and disposal practices that we considered to be standard in the industry at the time, repair and maintenance activities on rigs and equipment stored in these service yards may have resulted in the disposal or release of hydrocarbons or other wastes at or from these yards or at or from other locations where these wastes have been taken for treatment, storage or disposal. In addition, we lease properties that in the past were operated by third parties whose operations were not under our control. These properties and the hydrocarbons or hazardous substances handled thereon may be subject to CERCLA, RCRA and analogous state laws. Under these type of laws, we could be required to remove or remediate previously released hazardous substances, wastes or property contamination.

 

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Our operations are subject to the federal Clean Air Act and comparable state laws and regulations. These laws and regulations regulate emissions of air pollutants from various industrial sources, including our non-road mobile engines, and impose various monitoring and reporting requirements. The EPA has published proposed New Source Performance Standards (NSPS) and National Emissions Standards for Hazardous Air Pollutants (NESHAP) that, if adopted as proposed, would amend existing NSPS and NESHAP standards for oil and gas facilities, as well as create new NSPS standards for oil and gas production, transmission and distribution facilities. Compliance with the increasingly stringent emissions regulations may result in increased costs as we continue to grow. Federal and state regulatory agencies can impose administrative, civil and criminal penalties for non-compliance with air permits or other requirements of the federal Clean Air Act and associated state laws and regulations.

We also seek to manage environmental liability risks through provisions in our contracts with our customers that allocate risks relating to surface activities associated with the fracturing process to us and risks relating to “down-hole” liabilities to our customers. Our contracts generally require our customers to indemnify us against pollution and environmental damages originating below the surface of the ground or arising out of water disposal, or otherwise caused by the customer, other contractors or other third parties. In turn, our contracts generally require us to indemnify our customers for pollution and environmental damages originating at or above the surface caused solely by us. We seek to maintain consistent risk-allocation and indemnification provisions in our customer agreements to the greatest extent possible. Some of our contracts may, however, contain less explicit indemnification provisions, which would typically provide that each party will indemnify the other against liabilities to third parties resulting from the indemnifying party’s actions, except to the extent such liability results from the indemnified party’s gross negligence, willful misconduct or intentional act.

Federal and state occupational safety and health laws require us to organize and maintain information about hazardous materials used, released or produced in our operations. Certain portions of this information must be provided to employees, state and local governmental authorities and local citizens. We are also subject to the requirements and reporting set forth in federal workplace standards.

We have made and will continue to make expenditures to comply with environmental, health and safety regulations and requirements. These are necessary business costs in the oilfield services industry. Although we are not fully insured against all environmental, health and safety risks, and our insurance does not cover any penalties or fines that may be issued by a governmental authority, we maintain insurance coverage which we believe is customary in the industry. Moreover, it is possible that other developments, such as stricter and more comprehensive environmental, health and safety laws and regulations, as well as claims for damages to property or persons, resulting from company operations, could result in substantial costs and liabilities, including administrative, civil and criminal penalties, to us. We believe that we are in material compliance with applicable environmental, health and safety laws and regulations. We believe that the cost of maintaining compliance with these law and regulations will not have a material adverse effect on our business, financial position and results of operation, but new or more stringent regulations could increase the cost of doing business and could have a material adverse effect on our business. Moreover, accidental releases or spills may occur in the course of our operations, causing us to incur significant costs and liabilities, including for third-party claims for damage to property and natural resources or personal injury.

Hydraulic Fracturing.    Vast quantities of oil, natural gas liquids and natural gas deposits exist in deep shale and other formations. It is customary in our industry to recover oil, natural gas liquids and natural gas from these deep shale formations through the use of hydraulic fracturing, combined with sophisticated horizontal drilling. Hydraulic fracturing is the process of creating or expanding cracks, or fractures, in formations underground where water, sand and other additives are pumped under high

 

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pressure into the formation. These formations are generally geologically separated and isolated from fresh ground water supplies by protective rock layers.

Legislative, regulatory and enforcement efforts at the federal level and in some states have been initiated to require or make more stringent the permitting and compliance requirements for our oilfield services, including hydraulic fracturing. Hydraulic fracturing is typically regulated by state oil and gas commissions. However, the EPA recently asserted federal regulatory authority over hydraulic fracturing involving diesel fuels under the Safe Drinking Water Act’s Underground Injection Control Program and has begun the process of drafting guidance documents for permitting authorities and the industry on the process for obtaining a permit for hydraulic fracturing involving diesel fuel. Industry groups have filed suit challenging the EPA’s assertion of authority as improper rule making. The EPA also has commenced a study of the potential environmental impacts of hydraulic fracturing activities, with results of the study anticipated to be available by late 2012. The results of the EPA’s guidance, including its definition of diesel fuel, the related litigation, the EPA’s study, and other analyses by federal and state agencies to assess the impacts of hydraulic fracturing could each spur further action towards federal legislation and regulation of hydraulic fracturing activities.

Also, for the second consecutive session, legislation has been introduced in Congress to provide for federal regulation of hydraulic fracturing and to require disclosure of the chemicals used in the fracturing process. At this time, it is not possible to estimate the potential impact on our business of these state actions or the enactment of additional federal or state legislation or regulations affecting hydraulic fracturing. In addition, there is a growing trend among states that require us to provide information about the chemicals and products we maintain on location and use during hydraulic fracturing activities. Many of these laws and regulations require that we disclose information about the chemicals and products, including, in some instances, confidential and/or proprietary information. In certain cases, these chemicals and products are manufactured and/or imported by third parties and we therefore must rely upon such third parties for such information. Compliance or the consequences of any failure to comply by us could have a material adverse effect on our business, financial condition and operational results.

Climate Change.    Various state governments and regional organizations comprising state governments are considering enacting new legislation and promulgating new regulations governing or restricting the emission of greenhouse gases from sources such as our equipment and operations. Legislative and regulatory proposals for restricting greenhouse gas emissions or otherwise addressing climate change could require us to incur additional operating costs and could adversely affect the oil and natural gas industry and, therefore, could reduce the demand for our products and services. The potential increase in our operating costs could include new or increased costs to obtain permits, operate and maintain our equipment and facilities, install new emission controls on our equipment and facilities, acquire allowances to authorize our greenhouse gas emissions, pay taxes related to our greenhouse gas emissions and administer and manage a greenhouse gas emissions program. Moreover, incentives to conserve energy or use alternative energy sources could reduce demand for oil, natural gas liquids and natural gas. The EPA and the National Highway Traffic Safety Administration recently announced their intent to propose coordinated rules to regulate greenhouse gas emissions from heavy-duty engines and vehicles, and light-duty vehicles. Proposed rules have not been issued. Even without federal legislation or regulation of greenhouse gas emissions, states may pursue the issue either directly or indirectly. Restrictions on emissions of methane or carbon dioxide that may be imposed in various states could adversely affect the oil and natural gas industry and, therefore, could reduce the demand for our products and services.

 

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Cyclical Nature of Industry

We operate in a highly cyclical industry. The main factor influencing demand for oilfield services is the level of drilling activity by E&P companies, which in turn depends largely on current and anticipated future crude oil and natural gas prices and production depletion rates. The most critical factor in assessing the outlook for the industry is the worldwide supply and demand for oil and the domestic supply and demand for natural gas. Demand for oil and natural gas is cyclical and is subject to large and rapid fluctuations. This is primarily because the industry is driven by commodity demand and corresponding price increases. When oil and natural gas price increases occur, producers increase their capital expenditures, which generally results in greater revenues and profits for oilfield service companies. The increased capital expenditures also ultimately result in greater production, which historically has resulted in increased supplies and reduced prices that, in turn, tends to reduce demand for oilfield services. For these reasons, our results of operations may fluctuate from quarter to quarter and from year to year, and these fluctuations may distort period-to-period comparisons of our results of operations.

Legal Proceedings

We are subject to various legal proceedings and claims arising in the ordinary course of our business. Our management does not expect the outcome of any of these known legal proceedings, individually or collectively, to have a material adverse effect on our financial condition or results of operations.

 

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MANAGEMENT

Directors, Executive Officers and Significant Employees

The following table sets forth information about our executive officers, certain significant employees and our directors. Presently, each of the persons listed as an executive officer in the table below serves in a corresponding position with COS LLC and COO. There are no family relationships among any of our executive officers.

 

Name

   Age     

Position

Jerry L. Winchester

     53       Director and Chief Executive Officer

Cary D. Baetz

     47       Chief Financial Officer

James G. (“Jay”) Minmier

     47       President—Nomac Drilling, L.L.C.

William R. (“Bill”) Stanger

     58       President—Performance Technologies, L.L.C.

Zachary M. (“Zac”) Graves

     36       President—Thunder Oilfield Services, L.L.C.

Alan D. (“Al”) Lavenue

     51       President—Compass Manufacturing, L.L.C.

Aubrey K. McClendon

     52       Director

Steven C. (“Steve”) Dixon

     53       Director

Domenic J. (“Nick”) Dell’Osso, Jr  

     35       Director
      Director
      Director
      Director

Jerry L. Winchester, 53, has served as our Chief Executive Officer since September 2011. From November 2010 to September 2011, Mr. Winchester served as the Vice President—Boots & Coots of Halliburton. From July 2002 to September 2010, Mr. Winchester served as the President and Chief Executive Officer of Boots & Coots International Well Control, Inc. (“Boots & Coots”), an NYSE-listed oilfield services company specializing in providing integrated pressure control and related services. In addition, from 1998 until September 2010, Mr. Winchester served as a director of Boots & Coots and from 1998 until May 2008, served as Chief Operating Officer of Boots & Coots. Mr. Winchester started his career with Halliburton in 1981 and received a Bachelor of Science degree from Oklahoma State University.

Cary D. Baetz, 47, has served as our Chief Financial Officer since January 2012. From November 2010 to December 2011, Mr. Baetz served as Senior Vice President and Chief Financial Officer of Atrium Companies, Inc. and, from August 2008 to September 2010, served with Mr. Winchester as Chief Financial Officer of Boots & Coots. From 2005 to 2008, Mr. Baetz served as Vice President of Finance, Treasurer and Assistant Secretary of Chaparral Steel Company. Prior to joining Chaparral, Mr. Baetz had been employed since 1996 with Chaparral’s parent company, Texas Industries Inc. From 2002 to 2005, he served as Director of Corporate Finance of Texas Industries Inc. Mr. Baetz received a Bachelor of Science degree from Oklahoma State University and a Master of Business Administration degree from the University of Arkansas.

James G. (“Jay”) Minmier, 47, has served as President of Nomac Drilling, L.L.C., which operates our drilling segment, since June 2011. Prior to joining our company, from August 2005 to June 2011, Mr. Minmier served as Vice President and General Manager for Precision Drilling Corporation. Mr. Minmier has more than twenty years experience with drilling contractors, notably Grey Wolf Inc. and Helmerich & Payne, Inc. Mr. Minmier received a Bachelor of Science degree from the University of Texas at Arlington and a Master of Business Administration degree from the University of West Florida.

William R. (“Bill”) Stanger, 58, has served as the President of Performance Technologies, L.L.C., which operates our hydraulic fracturing segment, since January 2011. Mr. Stanger joined Chesapeake in January 2010 as President of Great Plains Oilfield Rentals, L.L.C. Prior to joining Chesapeake, from

 

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1987 to January 2010, Mr. Stanger served in various domestic and international management capacities with Schlumberger Limited, including Well Services Vice President of Operations North America and Well Services Vice President of Global Sales. Mr. Stanger received a Bachelor of Science degree from the University of Tulsa.

Zachary M. (“Zac”) Graves, 36, has served as President of Thunder Oilfield Services, L.L.C., which includes Great Plains Oilfield Rental, L.L.C., Hodges Trucking Company, L.L.C. and Oilfield Trucking Solutions, L.L.C., since June 2011. Prior to joining our company, from April 2003 to June 2011, Mr. Graves served in various capacities at Bronco Drilling Company, Inc., including as its Executive Vice President of Operations and Chief Financial Officer. Mr. Graves received a Bachelor of Business Administration degree from the University of Oklahoma.

Alan D. (“Al”) Lavenue, 51, has served as President of Compass Manufacturing, L.L.C., which operates our manufacturing segment, since its formation in 2007. Mr. Lavenue has also served as the President of MidCon Compression, L.L.C., a wholly owned subsidiary of Chesapeake providing natural gas compression rental and related compression services to Chesapeake and its affiliates, since April 2006. Mr. Lavenue joined Chesapeake in September 2003 as General Manager of Midcon Compression. Before joining Chesapeake, Mr. Lavenue served as the Vice President of Sales for Hanover Compressor Company from April 1995 through September 2003. Mr. Lavenue holds a Bachelor of Science degree from Texas A&M University.

Aubrey K. McClendon, 52, has served as Chairman of the Board, Chief Executive Officer and a director of Chesapeake since co-founding Chesapeake in 1989. We believe that Mr. McClendon’s extensive energy industry background and relationship with Chesapeake, particularly his leadership skills in serving as Chairman of the Board and Chief Executive Officer of Chesapeake and his instrumental role in the formulation and promotion of national and local initiatives that promote U.S natural gas as the best solution for our nation’s future energy needs, bring important experience and skill to the board. Mr. McClendon has also served as a director of the general partner of Chesapeake Midstream Partners, L.P. (NYSE:CHKM) since 2010. From 1982 to 1989, Mr. McClendon was an independent producer of oil and natural gas. Mr. McClendon graduated from Duke University in 1981.

Steven C. (“Steve”) Dixon, 53, has served as Executive Vice President—Operations and Geosciences and Chief Operating Officer of Chesapeake since February 2010. Mr. Dixon served as Executive Vice President—Operations and Chief Operating Officer of Chesapeake from 2006 to February 2010 and as Senior Vice President—Production of Chesapeake from 1995 to 2006. He also served as Vice President—Exploration of Chesapeake from 1991 to 1995. Mr. Dixon was a self-employed geological consultant in Wichita, Kansas from 1983 through 1990. He was employed by Beren Corporation in Wichita, Kansas from 1980 to 1983 as a geologist. Mr. Dixon graduated from the University of Kansas in 1980.

Domenic J. (“Nick”) Dell’Osso, Jr., 35, has served as Executive Vice President and Chief Financial Officer of Chesapeake since November 2010. Mr. Dell’Osso has also served as a director of the general partner of Chesapeake Midstream Partners, L.P. (NYSE:CHKM) since June 2011. Mr. Dell’Osso served as Vice President—Finance of Chesapeake and Chief Financial Officer of Chesapeake’s wholly owned midstream subsidiary, Chesapeake Midstream Development, L.P., from August 2008 to November 2010. Prior to joining Chesapeake, Mr. Dell’Osso was an energy investment banker with Jefferies & Co. from 2006 to August 2008 and Banc of America Securities from 2004 to 2006. Mr. Dell’Osso graduated from Boston College in 1998 and received a Master of Business Administration degree from the University of Texas at Austin in 2003.

 

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Board of Directors

Our certificate of incorporation and bylaws will provide that the Board of Directors shall consist of not less than              directors, nor more than              directors, and the number of directors may be changed only by resolution of the Board of Directors. Our directors will be elected annually to serve until the next meeting of shareholders or until their successors are duly elected and qualified. Upon completion of this offering, we anticipate that we will have              directors: Messrs. Dell’Osso, Dixon, McClendon, Winchester,             ,              and             .

Initially, our Board of Directors will consist of a single class of directors, each serving one year terms. We expect that our certificate of incorporation will provide that our Board of Directors will become a classified board, divided into three classes of directors, with each class as nearly equal in number as possible, serving staggered three year terms (other than directors which may be elected by holders of preferred stock, if any) upon the earlier of (a) such time as Chesapeake no longer beneficially owns at least a majority of the combined voting power of all of our outstanding common stock and (b) such time as we have 1,000 or more holders of record of our common stock.

Based upon the listing standards of the NYSE and SEC regulations, we anticipate that our Board of Directors will determine that Messrs.             ,             and             are “independent” under the standards of the NYSE. Although we have not established any specific objective criteria for service on our board, we anticipate that we will offer positions on our Board of Directors to persons who have significant experience relevant to companies in our industry and other qualifications that the existing members of our board believe will enable such persons to make significant contributions to our company. In addition, we will seek to identify candidates to fill the positions who meet the requirements for service on our Audit Committee, as described below.

Corporate Governance Guidelines and Board Matters

Upon completion of this offering, we will be a “controlled company” under the NYSE corporate governance rules for so long as Chesapeake owns more than 50% of the combined voting power of our common stock after the completion of this offering. As a result, we will be eligible for exemptions from provisions of the NYSE corporate governance standards, including (a) the requirement that a majority of the Board of Directors consist of independent directors, (b) the requirement that we have a nominating and corporate governance committee that is composed entirely of independent directors with a written charter addressing the committee’s purpose and responsibilities, (c) the requirement that we have a compensation committee that is composed entirely of independent directors with a written charter addressing the committee’s purpose and responsibilities and (d) the requirement that there be an annual performance evaluation of the corporate governance and compensation committees.

Following this offering, we intend to utilize these exemptions. As a result, we will not be required to have a majority of independent directors nor will we have nominating and corporate governance and compensation committees. Accordingly, you will not have the same protections afforded to shareholders of companies that are subject to all of the NYSE corporate governance requirements. In the event that we cease to be a controlled company within the meaning of these rules, we will be required to comply with these provisions within the transition periods specified in the NYSE corporate governance rules.

Committees of the Board of Directors

Prior to the closing of this offering, our Board of Directors will establish an Audit Committee and may establish such other committees as the Board of Directors may determine from time to time.

 

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Audit Committee

We anticipate that the initial members of our Audit Committee will be Messrs.             ,             and             , each of whom is independent and financially literate. We anticipate that Mr.             will be the Chairman of the committee, and he is an “audit committee financial expert” as described in Item 407(d)(5) of Regulation S-K. Our Audit Committee will be authorized to assist the board in overseeing the integrity of our financial statements, the qualifications and independence of our independent auditor, the performance of our independent auditor and internal auditors, our compliance with legal and regulatory requirements, our risk exposures and the other responsibilities set forth in its charter.

Specifically, the Audit Committee will also be authorized to:

 

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appoint, retain or replace the independent auditor to conduct the annual audit of our consolidated financial statements;

 

  Ÿ  

review the proposed scope and results of the audit;

 

  Ÿ  

review and pre-approve the independent auditors’ audit and non-audit services rendered;

 

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approve the audit fees to be paid;

 

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review accounting and financial controls with the independent auditors and our financial and accounting staff;

 

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establish procedures for complaints received by us regarding accounting or auditing matters;

 

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oversee internal audit functions; and

 

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prepare the report of the Audit Committee that SEC rules require to be included in our annual meeting proxy statement.

Code of Business Conduct and Ethics

Our Board of Directors will adopt a code of business conduct and ethics applicable to our employees, directors and officers, in accordance with applicable U.S. federal securities laws and the corporate governance rules of the NYSE. Any waiver of this code may be made only by our Board of Directors and will be promptly disclosed as required by applicable U.S. federal securities laws and the corporate governance rules of the NYSE.

Director Compensation

We were incorporated in April 2012 and, thus, did not have any directors or pay compensation to any directors in 2011. We believe that attracting and retaining qualified non-employee directors will be critical to our future growth. Following this offering, our non-employee directors are expected to receive compensation that is commensurate with the compensation that is offered to directors of companies that are similar to ours. We have not nor do we expect to compensate directors that are employees of us or Chesapeake for their service on our Board of Directors. We expect to reimburse our directors for reasonable out-of-pocket expenses that they incur in connection with their service as directors, in accordance with our general expense reimbursement policies.

 

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CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS

Relationship with Chesapeake

Prior to the consummation of this offering, COS LLC was a wholly owned subsidiary of Chesapeake. Following this offering and for the foreseeable future thereafter, Chesapeake will own a substantial majority of the combined voting power of our outstanding common stock and will have the ability influence or control all matters affecting our business.

We are entering into several agreements with Chesapeake in connection with this offering, including a tax receivable agreement, an amended and restated operating agreement of COS LLC and a registration rights agreement. Summaries of those agreements appear below.

Additionally, in connection with the establishment of COS LLC’s business in October 2011, COS LLC and COO entered into several agreements with Chesapeake, which are described below in “—Prior Transactions with Chesapeake.”

Offering Related Agreements with Chesapeake

Tax Receivable Agreement

As described in “Organizational Structure—Offering Transactions,” we intend to use substantially all of the net proceeds from this offering to acquire newly-issued Class A units from COS LLC. In addition, as described in “Use of Proceeds,” we intend to cause COS LLC to distribute a portion of such net proceeds to Chesapeake. Following this offering, Chesapeake may exchange its Class B units of COS LLC for shares of our Class A common stock on a one-for-one basis. The acquisition of newly-issued Class A units, the distribution to Chesapeake of a portion of the net proceeds of this offering and future exchanges of Class B units in COS LLC for Class A common stock are expected to result in an increase in the tax basis of the assets of COS LLC and additional deductions allocated to us. In addition, recent acquisitions by us have resulted in an increase, at the time of such acquisition, in the tax basis of the assets acquired. These increases in tax basis and additional deductions may reduce the amount of tax that we would otherwise be required to pay in the future.

We will enter into a tax receivable agreement with Chesapeake that will require us to pay Chesapeake 85% of the amount of tax benefits, that we realize (or we are deemed to realize, in the case of an early termination payment by us, or a change of control, as discussed below) as a result of (a) the increase in tax basis in the assets of COS LLC that arose from certain recent acquisitions by us; (b) any tax basis increase resulting from COS LLC’s distribution of offering proceeds by COS LLC to Chesapeake; (c) the tax basis increases resulting from exchanges by Chesapeake of its Class B units of COS LLC for shares of our Class A common stock; (d) additional deductions allocated to us pursuant to Section 704(c) of the Code to reflect the difference between the fair market value and the adjusted tax basis of COS LLC’s assets as of the date of this offering and (e) imputed interest deemed to be paid by us as a result of, and additional tax basis arising from, payments under the tax receivable agreement. We expect to benefit from the remaining 15% of cash savings, if any, realized.

For purposes of the tax receivable agreement, tax benefits will be computed by comparing our actual income tax liability to the amount of such taxes that we would have been required to pay had the tax basis increases and additional deductions listed in the prior paragraph not been available to us. The term of the tax receivable agreement will commence upon consummation of this offering and will continue until all such tax benefits have been utilized or expired, unless we exercise our right to terminate the tax receivable agreement for an amount based on an agreed-upon value of payments remaining to be made under the agreement.

 

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We will record amounts payable under the tax receivable agreement as a liability in our consolidated financial statements, which liability will be increased upon the exchanges by Chesapeake of Class B units of COS LLC for shares of our Class A common stock by an amount equal to 85% of the estimated future tax benefits, if any, relating to the increase in tax basis associated with any such exchanges. Estimating the amount of payments that we may be required to make under the tax receivable agreement is imprecise by its nature, because the actual increase in our share of the tax basis, as well as the amount and timing of any payments under the tax receivable agreement, will vary depending upon a number of factors, including:

 

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the timing of exchanges by Chesapeake—for instance, the increase in any tax deductions will vary depending on the fair market value, which may fluctuate over time, of the depreciable and amortizable assets of COS LLC at the time of the exchanges;

 

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the market price of our Class A common stock at the time of exchanges by Chesapeake—the increase in our share of the basis in the assets of COS LLC, as well as the increase in any tax deductions, will be related to the market price of our Class A common stock at the time of these exchanges;

 

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the extent to which these exchanges are taxable—if an exchange is not taxable for any reason (for instance, if Chesapeake exchanges Class B units of COS LLC in order to make a charitable contribution), increased deductions will not be available;

 

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the tax rates in effect at the time we utilize the increased amortization and depreciation deductions; and

 

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the amount and timing of our income—we will be required to pay 85% of the tax savings, as and when realized, if any. If we do not have taxable income, we generally will not be required to make payments under the tax receivable agreement for that taxable year because no tax savings will have been actually realized.

We expect that the payments that we make under the tax receivable agreement will be substantial. Assuming no material changes in the relevant tax law, and that we earn sufficient taxable income to realize the full tax benefit of the increased depreciation and amortization of the assets of COS LLC, we expect that future payments under the tax receivable agreement relating to increases in tax basis in the assets that arose from certain recent acquisitions, additional deductions allocated to us to reflect the difference between the fair market value and the adjusted tax basis of COS LLC’s assets as of the date of this offering, any tax basis increase resulting from COS LLC’s distribution to Chesapeake of a portion of the net proceeds of this offering, deductions for interest deemed paid by us and tax basis arising from payments under the tax receivable agreement will aggregate $         million and range from approximately $         million to $         million per year over the next 15 years (or $         million and range from approximately $         million to $         million per year over the next 15 years if the underwriters exercise their option to purchase additional shares of Class A common stock in full) and decline thereafter. Future payments under the tax receivable agreement in respect of subsequent exchanges of Class B units of COS LLC for shares of our Class A common stock will be in addition to these amounts and are expected to be substantial as well.

In addition, the tax receivable agreement provides that, upon certain mergers, asset sales, other forms of business combinations or other changes of control, our (or our successors’) obligations with respect to exchanged or acquired Class B units of COS LLC (whether exchanged or acquired before or after such transaction) would be based on certain assumptions, including that we would have sufficient taxable income to fully utilize the deductions arising from the increased tax deductions and tax basis and other benefits related to entering into the tax receivable agreement.

Decisions made by Chesapeake in the course of running our business, such as with respect to mergers, asset sales, other forms of business combinations or other changes in control, may influence

 

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the timing and amount of payments that are received by Chesapeake under the tax receivable agreement. For example, the earlier disposition of assets following an exchange or acquisition of Class B Units will generally accelerate payments under the tax receivable agreement and increase the present value of such payments, and the disposition of assets before an exchange or acquisition of Class B Units will increase Chesapeake’s tax liability without giving rise to any rights of Chesapeake to receive payments under the tax receivable agreement.

Payments are generally due under the tax receivable agreement within a specified period of time following the filing of our tax return for the taxable year with respect to which the payment obligation arises, although interest on such payments will begin to accrue from the due date (without extensions) of such tax return. In certain circumstances, we may defer that portion of our payments under the tax receivable agreement that is attributable to increases in tax basis arising from such payments, but only to the extent we do not have available cash to satisfy our payment obligations under the tax receivable agreement. Such deferred payments would accrue interest until the payments are made.

Payments under the tax receivable agreement will be based on the tax reporting positions that we will determine in accordance with such agreement. We will not be reimbursed for any payments previously made to Chesapeake under the tax receivable agreement; however, such payments will be determined based upon the cumulative net tax benefit to us, which would reflect any reduction in tax benefit for any prior period as a result of an audit. As a result, in certain circumstances, we could be required to make payments under the tax receivable agreement in excess of the benefits we actually realize.

Amended and Restated Operating Agreement of COS LLC

In connection with the closing of this offering, the operating agreement of COS LLC will be amended and restated to authorize two classes of units, the Class A units and the Class B units, and to appoint us as the sole managing member of COS LLC. The following is a description of the material terms of COS LLC’s amended and restated operating agreement.

Governance.    We will serve as the sole managing member of COS LLC. As such, we will control the business and affairs of COS LLC and be responsible for the management of its business. No other member of COS LLC, in its capacity as such, will have any authority or right to control the management of COS LLC or to bind it in connection with any matter.

Voting and Economic Rights of Members.    COS LLC will issue Class A units, which may only be issued to us, as the sole managing member, and Class B units, which may only be issued to Chesapeake. The Class A units and Class B units will have equivalent economic and other rights, except that each Class B unit will be exchangeable for a share of our Class A common stock. When Chesapeake exchanges a Class B unit of COS LLC for a share of our Class A common stock, we will automatically redeem and cancel a corresponding share of our Class B common stock. The Class A units and Class B units will not have any voting rights.

Net profits and net losses and distributions by COS LLC will be allocated and made to us and Chesapeake pro rata in accordance with the respective number of membership units of COS LLC held by us and Chesapeake. COS LLC will agree to make distributions to us and Chesapeake for the purpose of funding tax obligations in respect of income of COS LLC that is allocated to the members of COS LLC. However, COS LLC may not make any distributions to its members if doing so would violate any agreement to which it is then a party or any law then applicable to it, have the effect of rendering it insolvent or result in it having net capital lower than that required by applicable law. Additionally, because all of our operations are conducted through COO and COO’s revolving bank credit facility and

 

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the indenture governing the 2019 Senior Notes restrict the ability of COO to make distributions to COS LLC, COS LLC may not have any funds available to make distributions to us and Chesapeake in respect of tax obligations.

Coordination of COS Inc. and COS LLC.    At any time we issue a share of our Class A common stock for cash, the net proceeds will be promptly transferred to COS LLC, and COS LLC will issue one of its Class A units to us, or, alternatively, we may agree to transfer the net proceeds to Chesapeake in exchange for one Class B Unit of COS LLC, which Class B Unit will be converted automatically into a Class A Unit. If COS LLC issues other classes or series of equity securities, COS LLC will issue an equal amount of equity securities of COS LLC with designations, preferences and other rights and terms that are substantially the same as our newly-issued equity securities. Conversely, if we redeem any shares of our Class A common stock (or our equity securities of other classes or series) for cash, COS LLC will, immediately prior to such redemption, redeem an equal number of Class A units (or its equity securities of the corresponding classes or series) held by us, upon the same terms and for the same price, as the shares of our Class A common stock (or our equity securities of such other classes or series) are redeemed.

Issuances and Transfer of Units.    Class A units may only be issued to us, as the managing member of COS LLC, and are non-transferable. Class B units may only be issued to Chesapeake. Class B units may not be transferred without our consent, subject to such conditions as we may specify, except Chesapeake may transfer Class B units to an affiliate or to its shareholders without our consent. Chesapeake may not transfer any Class B units to any person unless Chesapeake transfers an equal number of shares of our Class B common stock to the same transferee.

Exchange Rights.    We have reserved for issuance             shares of our Class A common stock, which is the aggregate number of shares of Class A common stock expected to be issued over time upon the exchanges by Chesapeake of all Class B units of COS LLC outstanding immediately after this offering. Chesapeake may exchange its Class B units of COS LLC for shares of our Class A common stock at any time.

In connection with exercising its right to exchange Class B units of COS LLC for shares of our Class A common stock, Chesapeake must deliver a corresponding number of shares of our Class B common stock to us for redemption.

Indemnification and Exculpation.    To the extent permitted by applicable law, COS LLC will indemnify us, as its managing member, our authorized officers and our other employees and agents from and against any losses, liabilities, damages, costs, expenses, fees or penalties incurred in connection with serving in such capacities, provided that the acts or omissions of these indemnified persons are not the result of fraud, intentional misconduct or a violation of the implied contractual duty of good faith and fair dealing, or any lesser standard of conduct permitted under applicable law.

We, as the managing member of COS LLC, and our authorized officers and other employees and agents will not be liable to COS LLC, its members or their affiliates for damages incurred as a result of any acts or omissions of these persons, provided that the acts or omissions of these exculpated persons are not the result of fraud, intentional misconduct or a violation of the implied contractual duty of good faith and fair dealing, or any lesser standard of conduct permitted under applicable law.

Registration Rights Agreement

We plan to enter into a registration rights agreement with Chesapeake pursuant to which Chesapeake will be entitled to demand registration rights, including the right to demand that a shelf registration statement be filed, and “piggyback” registration rights, for shares of our Class A common

 

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stock that are issuable upon exchange of Class B units of COS LLC that it owns. In order to exercise its demand for registration, Chesapeake must deliver a written request to us. Until we become eligible to use Form S-3 for a registration of shares of our Class A common stock, Chesapeake will have the right to exercise demand rights for an agreed number of separate registrations. After we become eligible to use Form S-3 for a registration of shares of our Class A common stock, Chesapeake will have the right to exercise demand rights for an additional number of separate registrations, less the number of registrations that were effected prior to such date as a result of the exercise of such demand rights.

We expect that the registration rights agreement will provide that if our Board of Directors determines that it would be in our best interests, we may delay any demand registration for a period not to exceed 90 days, and such deferral may only be made by us once. We further expect it will provide that (a) we are not required to comply with any registration demand unless the anticipated aggregate offering amount equals or exceeds $50.0 million, (b) we will not be required to effect a demand registration within 150 days after the effective date of the registration statement for this offering or 60 days after the effective date of a previous demand registration, other than a shelf registration, and (c) we will not be required to effect more than two demand registrations during the first 12 months the registration rights agreement is effective or more than three demand registrations during any subsequent 12-month period. In addition, Chesapeake will have the right to participate in any public offering of our Class A common stock, other than an offering under a registration statement on Form S-4 or Form S-8 or any other forms not available for registering capital stock for sale to the public, subject to marketing considerations as determined by our managing underwriter for that offering and execution of a lock-up agreement.

We will pay all expenses in connection with any registration under the registration rights agreement, other than underwriters discounts and commissions, and provide customary indemnification. We anticipate that the registration rights described above will begin from the closing date of this offering and will cease to apply to a particular share of Class A common stock after it is, among others, (a) sold pursuant to a registration statement under the Securities Act of 1933; as amended (the “Securities Act”) (b) sold pursuant to Rule 144 under the Securities Act (or any successor provisions) or (c) otherwise transferred under circumstances where the subsequent public distribution of such shares will not require registration or qualification under the Securities Act or any similar state law. The members of our Board of Directors that are directors or officers of Chesapeake may be deemed to beneficially own or control Class B units of COS LLC that Chesapeake owns and may therefore personally benefit from the registration rights agreement. See “Principal Shareholder.”

Prior Transactions with Chesapeake

COS LLC and COO entered into the following transactions with Chesapeake in connection with the establishment of COS LLC’s business in October 2011.

 

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Master Services Agreement

We are a party to a master services agreement with Chesapeake, pursuant to which we provide drilling and other services and supply materials and equipment to Chesapeake. Drilling services are typically provided pursuant to modified IADC daywork drilling contracts. The specific terms of each request for other services are typically set forth in a field ticket or purchase or work order. The master services agreement contains general terms and provisions, including minimum insurance coverage amounts that we are required to maintain and confidentiality obligations with respect to Chesapeake’s business, and allocates certain operational risks between Chesapeake and us through indemnity provisions. The agreement will remain in effect until we or Chesapeake provide 30 days written notice of termination, although such agreement may not be terminated during the term of the services agreement described below.

We believe that our drilling contracts, field tickets or purchase or work orders with Chesapeake are substantially similar to those in prevailing industry contracts, specifically as they relate to pricing, liabilities and payment terms.

Services Agreement

We are a party to a services agreement with Chesapeake under which Chesapeake guarantees the utilization of a portion of our drilling rig and hydraulic fracturing fleets during the term of the agreement. Chesapeake guarantees that it will operate, on a daywork basis at market-based rates, the lesser of 75 of our drilling rigs or 80% of our operational drilling rig fleet, each referred to as a “committed rig,” subject to ratable reduction for each of our drilling rigs that is operated by a third-party customer. In addition, Chesapeake guarantees that each month it will utilize a number of our operational hydraulic fracturing fleets, up to a maximum of 13 fleets, to complete a minimum aggregate number of fracturing stages equal to 25 stages per month at market-based rates times the average number of our operational hydraulic fracturing fleets during such month, each referred to as a “committed stage,” subject to ratable reduction for each stage that we perform for a third-party customer during such month. In the event Chesapeake does not meet either the drilling commitment or the stage commitment, it will be required to pay us a non-utilization fee. For each day that a committed rig is not operated, Chesapeake must pay us our average daily operating cost for our operating drilling rigs for the preceding 30 days, plus 20%, and in no event less than $6,600 per day. For each committed stage not performed, Chesapeake must pay us $40,000. The services agreement is subject to the terms of our master services agreement with Chesapeake, has a five-year initial term ending October 25, 2016 and will thereafter automatically extend for successive one-year terms unless we or Chesapeake give written notice of termination at least 45 days prior to the end of a term; although Chesapeake has the right to terminate the agreement upon 30 days written notice after a change of control of us. For purposes of the services agreement, a change of control is deemed to have occurred if Chesapeake no longer controls us.

Facilities Lease Agreement

We are a party to a master lease agreement with Chesapeake pursuant to which we lease a number of the yards and other physical facilities out of which we conduct our operations. The initial term of the lease agreement ends December 31, 2014, after which the agreement will automatically renew for successive one-year terms unless we or Chesapeake terminate it. During such evergreen period, the amount of rent charged by Chesapeake will increase by 2.5% each year. We make monthly payments to Chesapeake under the lease agreement in respect of rent and our proportionate share of maintenance, operating expenses, taxes and insurance.

 

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Drilling Rig Sale-Leaseback Transactions

In a series of transactions since 2006, we sold 93 drilling rigs and related equipment to certain counterparties for an aggregate of $801.8 million and entered into two master lease agreements under which we agreed to lease the rigs from such counterparties for initial terms of five to ten years. In connection with our reorganization in October 2011, we assigned our rights under the master lease agreements to Chesapeake Equipment Finance, L.L.C. (“CEF”), a wholly owned subsidiary of Chesapeake, and entered into a sublease agreement with CEF under which we sublease all of the drilling rigs covered by the master lease agreements. Pursuant to the sublease agreement, we pay the same rent rates to CEF that it pays under the master lease agreements. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Contractual Commitments and Obligations.” The sublease will continue as to each drilling rig until the earlier of the expiration date for such rig set forth on an exhibit to the sublease or the applicable master lease agreement is terminated.

We are also a party to a drilling rig repurchase agreement with CEF, which provides that, to the extent CEF has the right to purchase a drilling rig under one of the master lease agreements, we may require CEF to exercise that right, and we will purchase that rig from CEF for a price equal to the greater of the price paid by CEF or the fair market value of the rig. Currently, we believe that the fair value market of drilling rigs is higher than the purchase price CEF would expect to pay under the master lease agreements.

Administrative Services Agreement

Chesapeake provides us with general and administrative services and the services of its employees pursuant to an administrative services agreement. In return for the general and administrative services provided by Chesapeake, we reimburse Chesapeake on a monthly basis for the overhead expenses incurred by Chesapeake on our behalf in accordance with its current allocation policy, which includes actual out-of-pocket fees, costs and expenses incurred in connection with the provision of any of the services under the agreement, including the allocable portion of the wages and benefits of Chesapeake employees who perform services on our behalf.

The administrative services agreement has a five-year initial term ending October 25, 2016 and will thereafter automatically extend for successive one-year terms unless we or Chesapeake give written notice of termination at least one year prior to the end of a term.

Tax Allocation Agreement

COS LLC is a party to a tax allocation agreement with Chesapeake that generally governs Chesapeake’s and COS LLC’s respective rights, responsibilities and obligations with respect to the payment of taxes and the preparation and filing of tax returns. At the time of the offering, however, the current tax allocation arrangement will be modified generally to provide for cash distributions by COS LLC to its unitholders for the payment of taxes due with respect to income earned by COS LLC.

Intercompany Promissory Note

On October 21, 2011, COS, LLC entered into a five-year, $1.5 billion revolving promissory note with Chesapeake. Amounts outstanding under the note bear interest at 6.875% per annum, and interest is payable semi-annually. The note is due on October 1, 2016, but demand for payment of the principal amount plus accrued and unpaid interest may be made by Chesapeake at any time. As of December 31, 2011, the note had an outstanding balance of $371.7 million. The balance of this note will be paid with a portion of the net proceeds of this offering and the note will be cancelled.

 

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Related Person Transactions Policy

We expect that our Board of Directors will adopt a written related person transactions policy prior to the completion of this offering pursuant to which our Board of Directors or a designated committee thereof will review all material facts of all related party transactions and either approve or disapprove entry into the related party transaction, subject to certain limited exceptions. We expect that such policy will provide that, in determining whether to approve or disapprove entry into a related party transaction, our Board of Directors or such committee shall take into account, among other factors, the following: (a) whether the related party transaction is on terms no less favorable to us than terms generally available to an unaffiliated third party under the same or similar circumstances and (b) the extent of the related party’s interest in the transaction. Further, we expect that such policy will require that all related party transactions required to be disclosed in our filings with the SEC be so disclosed in accordance with applicable laws, rules and regulations.

Under the SEC’s regulations, a “related party transaction” is a transaction, arrangement or relationship in which we or any of our subsidiaries was, is or will be a participant, and which involves an amount exceeding $120,000, and in which any related party had, has or will have a direct or indirect material interest. A “related party” is:

 

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any person who is, or at any time during the applicable period was, one of our executive officers or one of our directors;

 

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any person who is known by us to be the beneficial owner of more than 5% of our Class A common stock or Class B common stock;

 

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any immediate family member of any of the foregoing persons, which means any child, stepchild, parent, stepparent, spouse, sibling, mother-in-law, father-in-law, son-in-law, daughter-in-law, brother-in-law or sister-in-law of a director, executive officer or a beneficial owner of more than 5% of our Class A common stock, and any person (other than a tenant or employee) sharing the household of such director, executive officer or beneficial owner of more than 5% of our Class A common stock; and

 

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any firm, corporation or other entity in which any of the foregoing persons is a partner or principal or in a similar position or in which such person has a 10% or greater beneficial ownership interest.

 

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PRINCIPAL SHAREHOLDER

Prior to this offering, all of our outstanding common stock has been owned by Chesapeake. Immediately following this offering, the purchasers in this offering will own all of the outstanding shares of our Class A common stock and Chesapeake will own all of the outstanding shares of our Class B common stock. The table below sets forth information regarding the beneficial ownership of our Class B common stock by Chesapeake on a pro forma basis after giving effect to (a) the issuance of an aggregate of             shares of our Class A common stock in this offering, assuming no exercise of the underwriters’ option to purchase additional shares of Class A common stock, and (b) the issuance of an aggregate of             shares of our Class B common stock to Chesapeake.

None of our named executive officers or directors own any shares of our common stock.

Beneficial ownership is determined in accordance with the rules of the SEC and includes voting or investment power with respect to the securities.

 

    Class B Common Stock(2)    Combined Voting Power
     No. of
Shares
Before
Offering
   No. of
Shares
After
Offering
   No. of Shares After
Offering Assuming
Exercise of Option to
Purchase Additional
Shares of
Class A Common Stock
   % of
Combined
Voting
Power
Before
Offering
   % of
Combined
Voting
Power
After
Offering(3)
   % of Combined Voting
Power After Offering
Assuming Exercise of
Option to Purchase
Additional Shares of
Class A Common Stock(3)

Chesapeake Energy Corporation(1)

                   

 

(1) Chesapeake Energy Corporation is the ultimate parent entity of, and owns its interest in our Class B common stock through, Chesapeake Operating, Inc. (“COI”). Chesapeake Energy Corporation may be deemed to be the beneficial owner of the Class B common stock owned by COI. The address of Chesapeake Energy Corporation and COI is 6100 North Western Avenue, Oklahoma City, Oklahoma 73118.
(2) COI will not own any shares of Class A common stock immediately following this offering. However, COI will own             Class B common units of COS LLC which are exchangeable for shares of our Class A common stock at any time following this offering. As a result, COI and Chesapeake Energy Corporation may be deemed to beneficially own the shares of Class A common stock for which such Class B units are exchangeable. If COI exchanged all of its Class B common units for shares of our Class A common stock, it would own none of our shares of Class B common stock, it would own              shares, or             %, of our Class A common stock and it would hold             % of our combined voting power.
(3) Each share of our Class B common stock is entitled to             votes per share, for as long as the number of shares of our Class B common stock outstanding constitutes at least             % of the total number of shares of our common stock outstanding.

 

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Index to Financial Statements

Ownership of Chesapeake Securities by Directors and Executive Officers

The following table sets forth, as of April 11, 2012, the number of shares of common stock of Chesapeake owned by each of our directors and executive officers and all of our directors and executive officers as a group. To our knowledge, the persons named in the table have sole investment and voting power with respect to the shares of common stock indicated, subject to community property laws where applicable. None of the persons in the table below beneficially owns greater than 1.0% of Chesapeake’s common stock. The address for all beneficial owners listed in the table below is 6100 North Western Avenue, Oklahoma City, Oklahoma 73118.

 

Name of beneficial owner

   Number of
shares of
common stock
owned
    Shares
underlying
options
exercisable
within 60
days
    Total
shares of
common
stock
beneficially
owned
 

Jerry L. Winchester

     —          —          —     

Cary D. Baetz

     —          —          —     

Aubrey K. McClendon

     1,780,170 (a)      —          1,780,170   

Steven L. Dixon

     535,380 (b)      77,500 (c)      612,880   

Domenic J. Dell’Osso, Jr.  

     62,861 (d)      —          62,861   

All directors and executive officers as a group

     2,378,411        77,500        2,455,911   

 

(a) Includes (i) 13,671 shares held by Chesapeake Investments, an Oklahoma limited partnership of which Mr. McClendon is sole general partner; (ii) 114,891 shares purchased on behalf of Mr. McClendon in the 401(k) Plan; (iii) 102,118 shares of vested common stock purchased on behalf of Mr. McClendon in the Chesapeake Energy Corporation Deferred Compensation Plan; and (iv) 1,095 shares held by Mr. McClendon’s son who shares the same household.
(b) Includes 27,826 shares held in the Chesapeake Energy Corporation 401(k) Plan, 54,790 shares of vested common stock held in the Chesapeake Energy Corporation Deferred Compensation Plan and 170,115 shares held in grantor retained annuity trusts.
(c) Represents shares of common stock which can be acquired through the exercise of stock options as of April 11, 2012 or within 60 days thereafter.
(d) Includes 1,693 shares held in the Chesapeake Energy Corporation 401(k) Plan, and 112 shares of vested common stock held in the Chesapeake Energy Corporation Deferred Compensation Plan.

 

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Index to Financial Statements

DESCRIPTION OF CAPITAL STOCK

The following is a description of the material terms of our amended and restated certificate of incorporation and amended and restated bylaws that will be in effect upon consummation of this offering. We refer you to our certificate of incorporation and bylaws, copies of which have been filed as exhibits to the registration statement of which this prospectus forms a part.

Authorized Capitalization

Upon completion of this offering, our authorized capital stock will consist of                 shares of Class A common stock, par value $0.001 per share, of which                 shares will be issued and outstanding,                 shares of Class B common stock, par value $0.001 per share, of which                 shares will be issued and outstanding, and                 shares of preferred stock, par value $0.001 per share, none of which will be issued and o