Final Prospectus

Chesapeake Oilfield Operating, L.L.C. is offering to exchange registered 6.625% Senior Notes due 2019, or the “exchange notes,” for any and all of its unregistered 6.625% Senior Notes due 2019, or the “original notes,” that were issued pursuant to a private placement on October 28, 2011. We refer to the original notes and the exchange notes together in this prospectus as the “Notes” or “notes.” We refer to this exchange as the “exchange offer.” The exchange notes are substantially identical to the original notes, except the exchange notes are registered under the Securities Act of 1933, as amended (the “Securities Act”), and the transfer restrictions and registration rights, and related special interest provisions, applicable to the original notes will not apply to the exchange notes. The exchange notes will represent the same debt as the original notes, and we will issue the exchange notes under the same indenture used in issuing the original notes.

See “Risk Factors” beginning on page 13 for a discussion of risks you should consider in connection with the exchange offer and an investment in the exchange notes.

result of market-making activities or other trading activities. We have agreed to make this prospectus available to such broker-dealers upon reasonable request for the period required by the Securities Act. See “The Exchange Offer — Purpose and Effects of the Exchange Offer” and “Plan of Distribution.”

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

YOU SHOULD RELY ONLY ON THE INFORMATION CONTAINED IN THIS PROSPECTUS AND IN THE ACCOMPANYING LETTER OF TRANSMITTAL. WE HAVE NOT AUTHORIZED ANYONE TO PROVIDE YOU WITH ANY OTHER OR DIFFERENT INFORMATION. IF YOU RECEIVE ANY UNAUTHORIZED INFORMATION, YOU MUST NOT RELY ON IT. THIS PROSPECTUS MAY ONLY BE USED WHERE IT IS LEGAL TO EXCHANGE THE ORIGINAL NOTES FOR THE EXCHANGE NOTES, AND THIS PROSPECTUS IS NOT AN OFFER TO EXCHANGE OR A SOLICITATION TO EXCHANGE THE ORIGINAL NOTES FOR THE EXCHANGE NOTES IN ANY JURISDICTION WHERE AN OFFER OR EXCHANGE WOULD BE UNLAWFUL. YOU SHOULD ASSUME THAT THE INFORMATION CONTAINED IN THIS PROSPECTUS IS ACCURATE ONLY AS OF THE DATE OF THIS PROSPECTUS.

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.

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:

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.

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, such data may not have been independently verified.

PROSPECTUS SUMMARY

This summary highlights selected information about us and the exchange offer contained elsewhere in this prospectus. This summary is not complete and does not contain all of the information that may be important to you or that you should consider before participating in the exchange offer or making an investment in the exchange notes. You should read carefully the entire prospectus.

On October 25, 2011, Chesapeake completed the process of reorganizing its oilfield services subsidiaries and operations (the “COS Reorganization”) as subsidiaries of COS Holdings, L.L.C. (“COS LLC”) and commenced providing all of its oilfield services through COS LLC and its wholly owned subsidiary, Chesapeake Oilfield Operating, L.L.C. (“COO”). As a result, the historical financial information presented in this prospectus for periods and as of dates prior to the COS Reorganization is the historical consolidated financial information of our “predecessor.” The historical financial information presented in this prospectus for periods and as of dates on or after the COS Reorganization is the historical consolidated financial information of COO.

In this prospectus, unless indicated otherwise or the context requires otherwise, references to the terms “we,” “our,” “us” and the “Company” generally refer to COS LLC and its consolidated subsidiaries, including COO and Chesapeake Oilfield Finance, Inc. (“COF”). However, with respect to rights and obligations under the notes, the related indenture and the registration rights agreement described in this prospectus, references to “we,” “our,” “us” and the “Company” refer to COO and not to any of its subsidiaries, other than COF. The financial information presented in this prospectus is that of COO and its consolidated subsidiaries, including COF and the subsidiary guarantors. References to “Chesapeake Energy Corporation” or “Chesapeake” refer to Chesapeake Energy Corporation and its wholly owned subsidiaries (excluding us), unless the context indicates otherwise.

Our Company

We are a diversified oilfield services company that provides a wide range of wellsite services primarily to Chesapeake, our founder and principal customer, and its working interest partners. We focus on providing services to Chesapeake that are strategic to its oil and natural gas operations, represent historical bottlenecks to those operations or provide relatively high margins to the service provider, including drilling, hydraulic fracturing, oilfield rentals, rig relocation, fluid transportation and disposal 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 working interest partners with services in the Eagle Ford, Utica, Granite Wash, Cleveland, Tonkawa, Mississippi Lime and Niobrara liquids-rich plays and the Barnett, Haynesville, Bossier and Marcellus natural gas shale plays.

Our business has grown rapidly since our first subsidiary was founded in 2001, both organically and through acquisitions. As of March 31, 2013, we owned or leased 116 land drilling rigs. As of March 31, 2013, we also operated (a) eight hydraulic fracturing fleets with an aggregate of 315,000 horsepower; (b) a diversified oilfield rentals business; (c) an oilfield trucking fleet consisting of 286 rig relocation trucks, 67 cranes and forklifts used in the movement of drilling rigs and other heavy equipment and 254 fluid hauling trucks; and (d) manufacturing capacity for up to 150 natural gas compressor packages per quarter, or approximately 85,000 horsepower in the aggregate per quarter. We continue to modernize our asset base and have received seven of our proprietary, fit-for-purpose PeakeRigs™ that utilize advanced electronic drilling technology. We are scheduled to receive three additional PeakeRigs™ by July 2013.

We are an indirect, wholly owned subsidiary of Chesapeake. During the three months ended March 31, 2013 and for the years ended December 31, 2012, 2011 and 2010, Chesapeake and its working interest partners accounted for approximately 94%, 94%, 94% and 96% of our revenues, respectively, and we expect to derive a substantial majority of our revenues from Chesapeake and its working interest partners for the foreseeable future. Please read “Risk Factors—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 and financial 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,” “Risk Factors—Risks Relating to Our Business—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” and “Risk Factors—Risks Relating to Our Relationship with Chesapeake.”

We conduct our business through five operating segments:

Drilling. Our drilling segment provides 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, 2013, we owned or leased a fleet of 116 land drilling rigs.

Hydraulic Fracturing. Our hydraulic fracturing segment provides hydraulic fracturing and other well stimulation 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, 2013, we owned eight hydraulic fracturing fleets with an aggregate of 315,000 horsepower.

Oilfield Rentals. Our oilfield rentals segment provides premium rental tools 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 tanks, mud tanks and environmental containment. We also provide air drilling, flowback services and services associated with the transfer of water to the wellsite for well completions.

Oilfield Trucking. Our oilfield trucking segment provides drilling rig relocation and logistics services as well as fluid handling services. Our trucks move drilling rigs, crude oil, other fluids and construction materials to and from the wellsite and also transport produced water from the wellsite. As of March 31, 2013, we owned a fleet of 286 rig relocation trucks, 67 cranes and forklifts and 254 fluid hauling trucks.

Other Operations. Our other operations primarily consist of our natural gas compressor manufacturing operations and corporate functions.

Industry Overview

Oilfield services 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 and ConocoPhillips, U.S.-based major integrated oil and gas companies, such as ExxonMobil and Chevron, and international major integrated oil and gas companies, such as Shell Oil Company, Total S.A., BP America, CNOOC Limited, Sinopec International Petroleum Exploration and Production Corporation and Statoil. Demand for domestic onshore oilfield services is a function of the willingness of E&P companies to make capital and operating 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 services companies. Likewise, significant decreases in the prices of those commodities typically lead E&P companies to reduce their capital expenditures, which diminishes 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 remained relatively low since 2009, largely due to discoveries of vast new natural gas resources in the U.S. Oil prices were volatile in 2012 due to increased domestic supply and economic and political uncertainty. Low natural gas prices have resulted in increased drilling activity in liquids-rich plays as operators have reduced less economical natural gas drilling activities.

In response to low natural gas prices, a number of E&P companies, including Chesapeake, have reduced dry natural gas drilling and production and redirected their activities and capital toward currently more economical liquids-rich plays. Liquids-rich plays are those that are characterized by production of predominantly oil and natural gas liquids (NGL) such as ethane, propane, butane and iso-butane, which are used as energy sources and manufacturing feedstocks. NGL prices have historically been highly correlated with oil prices rather than natural gas prices, although they have decoupled recently due to increased production. The proportion of rigs in the U.S. drilling for oil 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 oil surpassed the number of rigs drilling for natural gas.

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 resulted in more than $9.0 billion of drilling carries to Chesapeake.

Our Relationship with Chesapeake

We are an indirect, wholly owned subsidiary of Chesapeake. We are 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 certain agreements that we have entered into with Chesapeake and its affiliates, please see “Certain Relationships and Related Party Transactions.” For a discussion of the risks related to our relationship with Chesapeake, please see “Risk Factors—Risks Relating to Our Relationship with Chesapeake.”

Summary of the Exchange Offer

On October 28, 2011, Chesapeake Oilfield Operating, L.L.C. and Chesapeake Oilfield Finance, Inc. completed an unregistered offering of the original notes. As part of that offering, we entered into a registration rights agreement with the initial purchasers of the original notes, which we refer to as the registration rights agreement, in which we agreed, among other things, to offer to exchange the original notes for the exchange notes. The following is a summary of the principal terms of the exchange offer. A more detailed description is contained in the section of this prospectus titled “The Exchange Offer.”


Original Notes		6.625% Senior Notes due 2019, which were issued by Chesapeake Oilfield Operating, L.L.C. and Chesapeake Oilfield Finance, Inc. in a private placement on October 28, 2011.

Exchange Notes		6.625% Senior Notes due 2019, issued by Chesapeake Oilfield Operating, L.L.C. and Chesapeake Oilfield Finance, Inc. The terms of the exchange notes are substantially identical to the terms of the original notes, except that the exchange notes are registered under the Securities Act, and the transfer restrictions and registration rights, and related special interest provisions, applicable to the original notes will not apply to the exchange notes.

Exchange Offer		Pursuant to the registration rights agreement, we are offering to exchange up to $650.0 million principal amount of our exchange notes that have been registered under the Securities Act for an equal principal amount of our original notes.

		The exchange notes will evidence the same debt as the original notes, including principal and interest, and will be issued under and be entitled to the benefits of the same indenture that governs the original notes. Holders of the original notes do not have any appraisal or dissenter’s rights in connection with the exchange offer. Because the exchange notes will be registered, the exchange notes will not be subject to transfer restrictions and holders of original notes that tender and have their original notes accepted in the exchange offer will no longer have registration rights or the right to receive the related special interest under the circumstances described in the registration rights agreement. Please see “The Exchange Offer” for more information regarding the registration rights agreement.

Expiration Date		The exchange offer will expire at 5:00 p.m., New York City time, on July 15, 2013, which we refer to as the Expiration Date, unless we decide to extend it or terminate it early. We do not currently intend to extend the exchange offer. A tender of original notes pursuant to this exchange offer may be withdrawn at any time on or prior to the Expiration Date if we receive a valid written withdrawal request before the expiration of the exchange offer.

Conditions to the Exchange Offer		The exchange offer is subject to customary conditions, which we may, but are not required to, waive. Please see “The Exchange Offer—Conditions to the Exchange Offer” for more information regarding the conditions to the exchange offer.



Procedures for Tendering Original Notes		Unless you comply with the procedures described under “The Exchange Offer—Procedures for Tendering Original Notes—Guaranteed Delivery,” to participate in the exchange offer, on or prior to the Expiration Date you must tender your original notes by using the book-entry transfer procedures described in “The Exchange Offer—Procedures for Tendering Original Notes—Tenders of Original Notes; Book-Entry Delivery Procedure,” including transmission or delivery to the exchange agent of an agent’s message or a properly completed and duly executed letter of transmittal, with any required signature guarantee. In order for a book-entry transfer to constitute a valid tender of your original notes in the exchange offer, Wells Fargo Bank, National Association, as registrar and exchange agent, must receive a confirmation of book-entry transfer of your original notes into the exchange agent’s account at The Depository Trust Company prior to the Expiration Date.

		By signing or agreeing to be bound by the letter of transmittal, you will represent to us that, among other things: •you are acquiring exchange notes in the ordinary course of your business; •you have no arrangement or understanding with any person or entity to participate in a distribution of the exchange notes; •you are not our or any subsidiary guarantor’s “affiliate” as defined in Rule 405 of the Securities Act; •if you are not a broker-dealer, that you are not engaged in, and do not intend to engage in, the distribution of the exchange notes; and •if you are a broker-dealer that will receive exchange notes for your own account in exchange for original notes that were acquired by you as a result of market-making or other trading activities, that you will deliver a prospectus in connection with any resale of such exchange notes. If you are a broker-dealer, you may not participate in the exchange offer as to any original notes you purchased directly from us.

Guaranteed Delivery Procedures		If you wish to tender your original notes in the exchange offer, but such notes are not immediately available or if you cannot deliver your original notes and the other required documents prior to the expiration date, then you may tender original notes by following the procedures described below under “The Exchange Offer—Procedures for Tendering Original Notes—Guaranteed Delivery.”

Withdrawal; Non-Acceptance		You may withdraw any original notes tendered in the exchange offer by sending the exchange agent written notice of withdrawal at any time prior to 5:00 p.m., New York City time, on the Expiration Date. For further information regarding the withdrawal of tendered original notes, please see “The Exchange Offer—Withdrawal of Tenders.” If any tendered original notes are not accepted for exchange because they do not comply with the procedures set forth in this prospectus and the accompanying letter of transmittal, or because of our withdrawal of the exchange offer, the occurrence of certain other events set forth herein or otherwise, such unaccepted original notes will be returned, without expense, to the tendering holder promptly after the Expiration Date or our withdrawal of the exchange offer. For further information regarding conditions to the exchange offer, please see “The Exchange Offer—Conditions to the Exchange Offer.”

U.S. Federal Income Tax Considerations		The exchange of original notes for exchange notes in the exchange offer will not be a taxable event for U.S. federal income tax purposes. Please see “U.S. Federal Income Tax Considerations” for more information regarding the tax consequences to you of the exchange offer.



Use of Proceeds		The issuance of the exchange notes will not provide us with any proceeds. We are making this exchange offer solely to satisfy our obligations under the registration rights agreement we entered into with the initial purchasers of the original notes.

Fees and Expenses		We will pay all expenses incident to the exchange offer.

Exchange Agent		We have appointed Wells Fargo Bank, National Association as our exchange agent for the exchange offer. You can find the address and telephone number of the exchange agent elsewhere in this prospectus under the caption “The Exchange Offer—Exchange Agent.”

Resales of Exchange Notes		Based on interpretations by the staff of the Securities and Exchange Commission (SEC), as set forth in no-action letters issued to third parties, we believe that the exchange notes you receive in the exchange offer may be offered for resale, resold or otherwise transferred by you without compliance with the registration and prospectus delivery provisions of the Securities Act so long as certain conditions are met. See “The Exchange Offer—Purpose and Effects of the Exchange Offer” and “Plan of Distribution” for more information regarding resales.

Not Exchanging Your Original Notes		If you do not exchange your original notes in this exchange offer, you will continue to hold unregistered original notes and you will no longer be entitled to registration rights or the special interest provisions related thereto, except in the limited circumstances set forth in the registration rights agreement. See “The Exchange Offer—Consequences of Failure to Exchange.” In addition, you will not be able to resell, offer to resell or otherwise transfer your original notes unless you do so in a transaction exempt from the registration requirements of the Securities Act and applicable state securities laws or unless we register the offer and resale of your original notes under the Securities Act. Following the exchange offer, we will be under no obligation to, and we do not intend to, register your original notes, except under the limited circumstances set forth in the registration rights agreement.

Additional Documentation; Further Information; Assistance		Any questions or requests for assistance or additional documentation regarding the exchange offer may be directed to the exchange agent. Beneficial owners of original notes should contact their broker, dealer, commercial bank, trust company or other nominee for assistance in tendering their original notes in the exchange offer.

The Exchange Notes

The terms of the exchange notes and those of the outstanding original notes are substantially identical, except that the exchange notes are registered under the Securities Act, and the transfer restrictions and registration rights, and related special interest provisions, applicable to the original notes will not apply to the exchange notes. The exchange notes represent the same debt as the original notes for which they are being exchanged. Both the original notes and the exchange notes are governed by the same indenture. The brief summary below describes the principal terms of the exchange notes. Some of the terms and conditions described below are subject to important limitations and exceptions. The “Description of Exchange Notes” section of this prospectus contains a more detailed description of the terms and conditions of the exchange notes.


Issuers		Chesapeake Oilfield Operating, L.L.C. and Chesapeake Oilfield Finance, Inc.

Exchange Notes Offered		$650.0 million aggregate principal amount of 6.625% Senior Notes due 2019.

Maturity		November 15, 2019.

Interest		6.625% per annum payable semi-annually in arrears on May 15 and November 15 of each year.

Guarantees		The exchange notes initially will be guaranteed, jointly and severally, on a senior unsecured basis by all of Chesapeake Oilfield Operating, L.L.C.’s existing subsidiaries, other than certain immaterial subsidiaries, including Chesapeake Oilfield Finance, Inc. See “Description of Exchange Notes—Subsidiary Guarantees.”

Ranking		The exchange notes and guarantees will constitute senior unsecured debt of Chesapeake Oilfield Operating, L.L.C. and Chesapeake Oilfield Finance, Inc. and the guarantors. They will rank:

		•equally in right of payment with all of our existing and future senior unsecured indebtedness; •effectively junior in right of payment to all of our existing and future secured indebtedness and other obligations to the extent of the value of the assets securing such indebtedness or obligations, including indebtedness under our revolving bank credit facility; •effectively junior in right of payment to all of the indebtedness and other liabilities of any of our subsidiaries that do not guarantee the exchange notes, to the extent of the assets of those subsidiaries; and •senior to any of our future subordinated indebtedness. As of March 31, 2013, Chesapeake Oilfield Operating, L.L.C.’s and Chesapeake Oilfield Finance, Inc.’s outstanding debt was approximately $1.1 billion, of which $650.0 million was the original notes and $407.6 million was secured indebtedness outstanding under the revolving bank credit facility. In addition, Chesapeake Oilfield Operating, L.L.C. had the ability to access an additional $92.4 million under the revolving bank credit facility.



Optional Redemption		We may redeem the exchange notes, in whole or in part, at any time on or after November 15, 2015 at the redemption prices set forth in this prospectus plus accrued and unpaid interest, if any. See “Description of Exchange Notes—Optional Redemption.” At any time prior to November 15, 2014, subject to certain exceptions, we may on one or more occasions redeem up to 35% of the aggregate principal amount of the exchange notes with net cash proceeds of one or more qualified equity offerings at the redemption price set forth in this prospectus plus accrued and unpaid interest, if any. In addition, at any time prior to November 15, 2015, we may on one or more occasions redeem all or part of the exchange notes at a redemption price equal to 100% of the principal amount of the exchange notes redeemed, plus a “make-whole premium” described in this prospectus plus accrued and unpaid interest, if any. See “Description of Exchange Notes—Optional Redemption.”

Offer to Repurchase Following Change of Control		Upon a change of control, if we do not redeem the exchange notes, each holder of exchange notes will be entitled to require us to purchase all or a portion of its exchange notes at a purchase price equal to 101% of the principal amount thereof, plus accrued and unpaid interest, if any. Our ability to purchase the exchange notes upon a change of control will be limited by the terms of our then outstanding debt agreements. See “Description of Exchange Notes—Repurchase at the Option of Holders—Change of Control.”

Offer to Repurchase Following Certain Asset Sales		If we or our restricted subsidiaries engage in certain asset sales, we may either invest the net cash proceeds from such event in our business or prepay our senior debt, each within a certain period of time of such event, or we must make an offer to purchase a principal amount of the exchange notes equal to the excess net cash proceeds, with certain exceptions. The purchase price of the exchange notes will be 100% of their principal amount, plus accrued and unpaid interest, if any. See “Description of Exchange Notes— Repurchase at the Option of Holders—Asset Sales.”

Certain Covenants		The indenture governing the exchange notes, among other things, limits our ability and the ability of our restricted subsidiaries to:

		•sell assets;

		•declare dividends or make distributions on our equity interests or purchase or redeem our equity interests;

		•make investments or other specified restricted payments;

		•incur or guarantee additional indebtedness and issue disqualified or preferred equity;

		•create liens;

		•enter into agreements that restrict the ability of our restricted subsidiaries to pay dividends, make intercompany loans or transfer assets to us;

		•effect a merger, consolidation or sale of all or substantially all of our assets;



		• enter into transactions with affiliates; and

		• designate subsidiaries as unrestricted subsidiaries.

		These and other covenants are subject to important exceptions and qualifications as described under “Description of Exchange Notes—Certain Covenants.”

Covenant Suspension/Termination		If the exchange notes receive an investment grade rating by either Standard & Poor’s Ratings Services (S&P) or Moody’s Investors Service, Inc. (Moody’s), our obligation to comply with certain of the covenants in the indenture will be suspended, and if the exchange notes receive an investment grade rating by both S&P and Moody’s, then such obligations will terminate as described under “Description of Exchange Notes—Certain Covenants—Covenant Suspension and Termination.”

No Prior Market		The exchange notes will generally be freely transferable but are also new securities for which there initially will not be a market. We do not intend to apply for a listing of the exchange notes on any securities exchange or for their inclusion on any automated dealer quotation system. Accordingly, we cannot assure you as to the development or liquidity of any market for the exchange notes.

Book-Entry Form		The exchange notes will be issued in book-entry form and will be represented by one or more global securities registered in the name of Cede & Co., as nominee for The Depository Trust Company, or DTC. Beneficial interests in the exchange notes will be evidenced by, and transfers will be effected only through, records maintained by DTC participants.

Form and Denomination		Exchange notes will be issuable in minimum denominations of $2,000 and integral multiples of $1,000 in excess thereof.

Risk Factors		See “Risk Factors” and the other information in this prospectus for a discussion of the factors you should carefully consider before deciding to participate in the exchange offer.

SUMMARY HISTORICAL FINANCIAL DATA

The following tables set forth the summary historical financial data of COO and its predecessors. The summary historical financial data for each of the three-month periods ended March 31, 2013 and 2012 are derived from the unaudited condensed consolidated financial statements included elsewhere in this prospectus. The summary historical financial data for each of the years ended December 31, 2012, 2011 and 2010 are 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 services 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 financial statements of COF have not been presented in this prospectus as it has had no business transactions or activities to date and has no (or nominal) assets or liabilities.


	Three Months Ended March 31,						Years Ended December 31,
	2013			2012			2012			2011			2010
	(unaudited)
	(in thousands)
Income Statement Data:
Revenues, including revenues from affiliates	$	543,887		$	446,881		$	1,920,022		$	1,303,496		$	815,756
Operating costs		415,049			326,914			1,390,786			986,239			667,927
Depreciation and amortization		70,112			53,673			231,322			175,790			103,339
General and administrative, including expenses from affiliates		20,491			15,631			66,360			37,074			25,312
Losses (gains) on sales of property and equipment		374			(1,221	)		2,025			(3,571	)		(854	)
Impairments and other ⁽¹⁾		24			1,038			60,710			2,729			9

Operating income		37,837			50,846			168,819			105,235			20,023

Interest expense, including expenses from affiliates		(14,010	)		(12,616	)		(53,548	)		(48,802	)		(38,795	)
Losses from equity investees		(119	)		(163	)		(361	)		—			(2,243	)
Other income (expense)		524			184			1,543			(2,464	)		211

Total other expense		(13,605	)		(12,595	)		(52,366	)		(51,266	)		(40,827	)

Income (loss) before income taxes		24,232			38,251			116,453			53,969			(20,804	)
Income tax expense (benefit)		9,999			15,415			46,877			26,279			(4,195	)

Net income (loss)		14,233			22,836			69,576			27,690			(16,609	)

Less: Net Loss Attributable to Noncontrolling Interest		—			—			—			(154	)		(639	)

Net Income (Loss) Attributable to Chesapeake Oilfield Operating, L.L.C.	$	14,233		$	22,836		$	69,576		$	27,844		$	(15,970	)

Other Financial Data:
Adjusted EBITDA⁽²⁾(unaudited)	$	108,752		$	104,357		$	439,203		$	277,719		$	120,485
Capital expenditures (including acquisitions)	$	92,496		$	155,184		$	622,825		$	752,715		$	273,154


	As of March 31, 2013
	(in thousands)
	(unaudited)
Balance Sheet Data:
Cash	$	1,745
Total property and equipment, net	$	1,576,155
Total assets	$	2,196,597
Total long-term debt	$	1,057,600
Total equity	$	598,089

(1)	We recorded impairments of long-lived assets and lease termination costs in the amount of $35.8 million and $24.9 million, respectively, for the year ended December 31, 2012.

(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:

•

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;

•

is a financial measurement that is used by rating agencies, lenders and other parties to evaluate our creditworthiness; and

•

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):


	Three Months Ended March 31,					Years Ended December 31,
	2013		2012			2012		2011			2010
	(Unaudited)
	(in thousands)
Net income (loss)	$	14,233	$	22,836		$	69,576	$	27,690		$	(16,609	)
Interest expense		14,010		12,616			53,548		48,802			38,795
Income tax expense (benefit)		9,999		15,415			46,877		26,279			(4,195	)
Depreciation and amortization		70,112		53,673			231,322		175,790			103,339
Impairments		24		1,038			35,855		2,729			9
Losses (gains) on sales of property and equipment		374		(1,221	)		2,025		(3,571	)		(854	)

Adjusted EBITDA	$	108,752	$	104,357		$	439,203	$	277,719		$	120,485

You should carefully consider the risk factors set forth below as well as the other information contained under “Forward-Looking Statements” and elsewhere in this prospectus before deciding to participate in the exchange offer. This prospectus contains forward-looking statements that involve risks and uncertainties. Any of the following risks could materially and adversely affect our business, financial condition, results of operations or cash flows. In such a case, you may lose all or part of your original investment.

We are dependent on Chesapeake for a substantial majority of our revenues. Therefore, we are indirectly subject to the business and financial 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.

We have provided a substantial majority of all of our oilfield services to Chesapeake and its working interest partners. During the three months ended March 31, 2013 and for the years ended December 31, 2012, 2011 and 2010, Chesapeake and its working interest partners accounted for approximately 94%, 94%, 94% and 96% of our revenues, respectively, and we expect to derive a substantial majority of our revenues from Chesapeake and its working interest partners 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, results of operations and cash flows would be materially adversely affected. Accordingly, we are indirectly subject to the business and financial risks of Chesapeake, some of which are the following:

In particular, Chesapeake has historically pursued a strategy of making capital expenditures for land acquisition, drilling and completion of wells, and other activities in excess of its operating cash flows. To fund these expenditures, Chesapeake obtained capital from the debt and equity capital markets, oil and natural gas asset sales or joint ventures, counterparties in volumetric production payment transactions and other sources. Chesapeake has announced that it intends to fund 2013 capital expenditures from operating cash flows, borrowings under its bank credit facilities and, to the extent those sources are not sufficient, proceeds from asset sales and other financings. If Chesapeake is unable to consummate such asset sales or if they do not generate the proceeds that are anticipated, Chesapeake would be required to reduce its spending on drilling and completion activities, which would have a material adverse impact on our business, financial condition, results of operations and cash flows.

Our relationship with Chesapeake presents a number of additional risks to us. Please read “—Risks Relating 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 capital and operating 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:

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 services, 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 flows.

Natural gas prices declined significantly in late 2011 and 2012 to the lowest level in recent years, and while prices have risen from their lows, they remain depressed. As a result of depressed natural gas prices, many E&P companies, including Chesapeake, have reduced drilling in plays characterized by higher concentrations of dry natural gas. Although many of these companies, including Chesapeake, have refocused 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.

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 wellsite services, which may result in a reduction in the demand for our services, the rates we can charge and the utilization of our services. 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 or environmental 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 flows, 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 and hydraulic fracturing fleets in the U.S. over the past several years. Such increase, whether through new construction or refurbishment of existing equipment, could have a material adverse impact on market prices and utilization rates of the service-provider. 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 rates we charge to it. A reduction in the rates we charge would adversely affect our revenues and profitability. Such adverse effect on our revenues 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 operations in the future.

We generally do not have long term contracts in place that provide for the delivery of equipment, including, but not limited to, drill pipe, replacement parts and other equipment. 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 services companies and numerous other factors beyond our control could adversely affect our ability to procure equipment that we have not yet ordered or cause the prices of such equipment to increase. Price increases, delays in delivery and interruptions in supply may require us to increase capital and repair expenditures and incur higher operating costs. Each of these could have a material adverse effect on our business, financial condition, results of operations and cash flows.

We are dependent on a small number of suppliers for key raw materials and finished products.

We do not have long term contracts with third party suppliers of many of the raw materials and finished products that we use in large volumes in our operations, including, in the case of our hydraulic fracturing operations, proppants, acid, gels, including guar gum, chemicals and water, and fuels used in our equipment and vehicles. Especially during periods in which oilfield services are in high demand, the availability of raw materials and finished products used in our industry decreases and the price of such raw materials and finished products increases. We are dependent on a small number of suppliers for key raw materials and finished products. Our reliance on such suppliers could increase the difficulty of obtaining such raw materials and finished products in the event of shortage in our industry or cause us to pay higher prices to obtain such raw materials and finished products. Price increases, delays in delivery and interruptions in supply may require us to incur higher operating costs. Each of these could have a material adverse effect on our business, financial condition, results of operations and cash flows.

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 operate and manage our business. 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 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 thereby increasing our operating costs.

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 flows.

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 performed outdoors, and to the volatility and cyclical nature of the oilfield services 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 you 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 flows.

We participate in a capital intensive industry. We may not be able to finance 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 to us in the future. However, if our cash flows from operating activities and borrowings under our revolving bank credit facility are not sufficient to fund our capital expenditures budget, we would be required to fund these expenditures through debt or equity or alternative financing plans, such as:

If debt and equity capital or alternative financing plans are not available on favorable terms or at all, we would be required to curtail our capital spending, and our ability to 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 business, as well as our credit ratings and profile.” Any of the foregoing could materially and adversely affect our business, financial condition, results of operations and cash flows.

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 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 could materially and adversely affect our business, financial condition, results of operations and cash flows.

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, financial condition, results of operations and cash flows 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 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 business, financial condition, results of operations and cash flows. 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. See “Business—Risk Management and Insurance.”

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

Various federal legislative and regulatory initiatives have been undertaken which could result in additional requirements or restrictions being imposed on hydraulic fracturing operations. These regulations, if adopted, would establish additional levels of regulation at the federal level that could lead to operational delays and increased operating costs. At the same time, several states 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. 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 United States Environmental Protection Agency (EPA) has asserted federal regulatory authority over hydraulic fracturing activities involving diesel fuel (specifically, when diesel fuel is utilized in the stimulation fluid) under the Safe Drinking Water Act and is drafting guidance documents related to this newly asserted regulatory authority. There are also certain governmental reviews 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. In addition, 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 are unable to predict whether the proposed changes in laws or regulations or any other governmental proposals or responses will ultimately occur, and accordingly, we are unable to assess the potential financial or operational impact they may have on our business.

The adoption of any future federal, state or local laws or implementing regulations imposing reporting obligations on, or limiting or banning, the hydraulic fracturing process could make it more difficult to complete natural gas and oil wells and could have a material adverse impact on our business, financial condition, results of operations and cash flows.

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 flows. Additionally, an increase in regulatory requirements on oil and gas exploration and completion activities could significantly delay or interrupt our operations.

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.

At the federal level, the EPA has already made findings and issued regulations that require us to establish and report an inventory of greenhouse gas emissions. 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. 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. 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.

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 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, which could have a material adverse impact on our business, financial condition, results of operations and cash flows.

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

These constraints could delay our operations and materially increase our operating and capital costs. Unusually warm winters or cool 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, especially with respect to our hydraulic fracturing 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:

If we are unable to identify, make and successfully integrate acquired businesses, it could have a material adverse effect on our business, financial condition, results of operations and cash flows.

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

The operating and financial restrictions in our revolving bank credit facility and in the indenture governing the notes and any future financing agreements could restrict our ability to finance future operations or capital needs, or otherwise pursue our business activities. For example, the revolving bank credit facility and the indenture limit our and our subsidiaries’ ability to, among other things:

Furthermore, our revolving bank credit facility contains covenants requiring us to maintain a maximum consolidated leverage ratio and a minimum fixed charge cover.

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 us that would be likely to have a material adverse effect on our business, financial condition, results of operations and cash flows. The existence of these covenants may also prevent or delay us from pursuing business opportunities that we believe would otherwise benefit us.

We may incur additional debt and long-term lease obligations in the future.

Our revolving bank credit facility and the indenture governing the notes restrict but do not prohibit us from incurring additional indebtedness and other obligations in the future. If we incur additional debt, the related risks that we face could intensify. In addition, the revolving bank credit facility and the indenture governing the notes restrict but do not prohibit us 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 beginning in 2006, we sold 94 drilling rigs (of which 26 have been repurchased) and related equipment and entered into master lease agreements under which we agreed to lease the rigs from the buyers for initial terms ranging from five to ten years. All of these leases have been accounted for as operating leases and, as a result, our obligations under these leases are not reflected on our balance sheet. As of March 31, 2013, the aggregate undiscounted minimum future lease

payments under our operating leases was $337.5 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—Off-Balance Sheet Arrangements” and Note 4 “Commitments and Contingencies” to our unaudited condensed 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:

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

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. Therefore, we 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 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 (NHTSA) and the EPA 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, an impairment of equipment productivity, a 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, financial condition, results of operations and cash flows.

Our inability to obtain or implement new technology may cause us to become less competitive.

The oilfield services 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 or costly to obtain. As competitors and others use or develop new technologies in the future, we may be placed at a competitive disadvantage. Furthermore, 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 flows.

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.

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. 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 of our results of operations and financial condition had we operated as a standalone entity during such periods. Our future results will depend on our ability to efficiently manage our combined operations and execute our business strategy.

Oilfield anti-indemnity provisions enacted by many states may restrict or prohibit a party’s indemnification of us.

We typically enter into master services agreements with our customers governing the provision of our services, which agreements usually include certain indemnification provisions for losses resulting from operations. Such agreement may require each party to indemnify the other against certain claims regardless of the negligence or other fault of the indemnified party; however, many states place limitations on contractual indemnity agreements, particularly agreements that indemnify a party against the consequences of its own negligence. Furthermore, certain states, including Texas, Louisiana, New Mexico and Wyoming, have enacted statutes generally referred to as “oilfield anti-indemnity acts” expressly prohibiting certain indemnity agreements contained in or related to oilfield services agreements. Such oilfield anti-indemnity acts may restrict or void a party’s indemnification of us, which could have a material adverse effect on our business, financial condition, results of operations and cash flows.

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

Credit rating agencies such as S&P 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. In April 2012, S&P downgraded the outstanding indebtedness of Chesapeake. That downgrade or a future downgrade could cause us to experience an increase in our borrowing costs or difficulty accessing, or an inability to access, the capital markets and could also adversely affect our ability to make payments on our debt obligations. Please read “—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 and financial 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.”

Chesapeake is our sole beneficial owner and has the power to control us, and its interests may conflict with our interests and the interests of the holders of the notes.

Because it is our sole beneficial owner and our largest customer, Chesapeake has the power to control all aspects of our business, operations and governance, subject only to the terms of the revolving bank credit facility, indenture, other agreements we have made with third parties and certain of our agreements with Chesapeake. Please see “Certain Relationships and Related Party Transactions” for a more complete description of certain of our agreements with Chesapeake and its affiliates. As a result, Chesapeake has wide latitude to establish the business plan of and general direction for our company, to make significant decisions

regarding our ownership, approach to financing our operations and our capital structure, to make personnel decisions and decisions regarding our entry into acquisition, disposition and other material transactions. Although the revolving bank credit facility and indenture contain a number of restrictive covenants, these covenants do not regulate all decisions Chesapeake may make on our behalf or all actions it may take. Additionally, while the revolving bank credit facility and indenture contain covenants restricting certain affiliate transactions, such covenants are subject to important exceptions, including those applicable to our provision of services to Chesapeake and to Chesapeake’s provision of services to us. Chesapeake does not owe any fiduciary duties to the holders of notes and, because we are wholly owned, the holders of notes do not indirectly benefit from fiduciary duties that Chesapeake would owe to a minority owner. As a result, holders of the notes may rely only on the provisions of the indenture to protect their interests.

Chesapeake may, from time to time, make one or more investments in or enter into agreements with other companies, including certain companies that compete with us. In general, Chesapeake need not, and likely will not, consider our interests in making such decisions. Any of these potential conflicts of interest could have a material adverse effect on our business, financial condition, results of operations and cash flows.

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

The master services agreement, services agreement, administrative services agreement, facilities lease agreement and certain other agreements we have with Chesapeake were made in the context of an affiliated relationship and were not subject to the affiliate transactions covenants contained in the revolving bank credit facility and indenture. As a result, they may not be on terms that would exist in similar agreements negotiated at arm’s length between unrelated parties. In addition, these agreements may be amended, and Chesapeake, as the sole owner of our equity interests, will have control over our decision to agree to any such amendments, subject to the terms of the revolving bank credit facility and indenture. Please see “Certain Relationships and Related Party Transactions” for a more complete description of certain of our agreements with Chesapeake.

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 with 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 with 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. Please see “Certain Relationships and Related Party Transactions” for a more complete description of certain of our agreements with Chesapeake.

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

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 otherwise incur if we obtained such services ourselves. Please see “Certain Relationships and Related Party Transactions” for a more complete description of certain of our agreements with Chesapeake.

The notes and the guarantees will be unsecured and effectively subordinated to the rights of our secured indebtedness and structurally subordinated to the indebtedness of any of our present and future non-guarantor subsidiaries.

The notes and the guarantees will be general unsecured senior obligations ranking effectively junior to all of the issuers’ and guarantors’ existing and future secured debt, including obligations under our revolving bank credit facility to the extent of the value of the collateral securing such debt. The notes will also be structurally subordinated to any indebtedness and other liabilities of our present and future non-guarantor subsidiaries.

If the issuers or the guarantors are declared bankrupt, become insolvent or are liquidated or reorganized, their secured debt will be entitled to be paid in full from the assets, if any, securing such debt before any payment may be made with respect to the notes or the affected guarantees. Holders of the notes will participate ratably in the remaining assets with all holders of their unsecured indebtedness, including debt incurred after the notes are issued, that does not rank junior to the notes, including trade payables and all of the other general indebtedness, based upon the respective amounts owed to each holder or creditor. In any of the foregoing events, there may not be sufficient funds to pay amounts due on the notes. As a result, holders of the notes would likely receive less, ratably, than holders of secured indebtedness.

Certain of our present and future subsidiaries may not be required to guarantee the notes. Your right to receive payments on the notes could be adversely affected if any of our non-guarantor subsidiaries declares bankruptcy, liquidates or reorganizes.

Although all of our present subsidiaries, other than certain immaterial subsidiaries, will initially guarantee the notes, the guarantees are subject to release in certain circumstances, and in the future we may create or acquire other subsidiaries that are not required under the indenture to become guarantors. The notes will be structurally junior to the claims of all creditors, including trade creditors and tort claimants, of our subsidiaries that are not guarantors. In the event of the liquidation, dissolution, reorganization, bankruptcy or similar proceedings respecting the business of a subsidiary that is not a guarantor, creditors of that subsidiary would generally have the right to be paid in full before any distribution is made to us or the holders of the notes. Accordingly, there may not be sufficient funds remaining to pay amounts due on all or any of the notes.

The definition of change of control in the indenture governing the notes includes a phrase relating to the sale, lease or transfer of “all or substantially all” of our assets. There is no precisely established definition of the phrase “substantially all” under applicable law. Accordingly, your ability to require us to repurchase your notes as a result of a sale, lease or transfer of less than all of our assets to another individual, group or entity may be uncertain.

Many of the covenants contained in the indenture will be suspended or will terminate if the notes are rated investment grade.

If the notes receive an investment grade rating by either S&P or Moody’s, our obligation to comply with certain of the covenants and our repurchase obligation upon a change of control will terminate. These covenants restrict, among other things, our ability to pay distributions, incur debt and to enter into certain other transactions. There can be no assurance that the notes will ever be rated investment grade, or that if they are rated investment grade, that the notes will maintain such ratings. However, termination of these covenants would allow us to engage in certain transactions that would not be permitted while these covenants were in force.

You may find it difficult to sell your exchange notes as there is no established market for them. If a market does develop, it may be highly volatile.

Because there is no public market for the exchange notes, you may not be able to resell them. The exchange of original notes for exchange notes will be registered under the Securities Act but the exchange notes will constitute a new issue of securities with no established trading market. We do not intend to have the exchange notes listed on a national securities exchange. There can be no assurance that an active trading market for the exchange notes will develop, or if one does develop, that it will be sustained.

Historically, the market for non-investment grade debt has been highly volatile in terms of price. It is possible that the market for the exchange notes will also be volatile. This volatility in price may affect your ability to resell your exchange notes, the timing of their sale and any amount you receive for them. The trading market for the exchange notes may be adversely affected by:

Prospective investors in the exchange notes should be aware that they may be required to bear the financial risk of their investment for an indefinite period of time.

We may not be able to repurchase the notes upon a change of control or pursuant to an asset sale offer.

Upon a change of control as defined under the indenture governing the notes, the holders of notes will have the right to require us to offer to purchase all of the notes then outstanding at a price equal to 101% of their principal amount plus accrued and unpaid interest, if any. In order to obtain sufficient funds to pay the purchase price of the outstanding notes, we expect that we would have to refinance the notes. We cannot assure you that we would be able to refinance the notes on reasonable terms, if at all. Our failure to offer to purchase all outstanding notes or to purchase all validly tendered notes would be an event of default under the indenture. Such an event of default may cause the acceleration of our other debt. Our other debt also may contain restrictions on repayment requirements with respect to specified events or transactions that constitute a change of control under the indenture.

In addition, in certain circumstances specified in the indenture governing the notes, we will be required to commence an asset sale offer, as defined in the indenture, pursuant to which we will be obligated to purchase the applicable notes at a price equal to 100% of their principal amount plus accrued and unpaid interest, if any. Our other debt may contain restrictions that would limit or prohibit us from completing any such asset sale offer. Our failure to purchase any such notes when required under the indenture would be an event of default under the indenture. Such an event of default may cause the acceleration of our other debt.

Changes in our credit ratings or the debt markets may adversely affect the market price of the notes.

The price for the notes will depend on a number of factors, including but not limited to:

The condition of the financial markets and prevailing interest rates have fluctuated in the past and are likely to fluctuate in the future. Such fluctuations could have an adverse effect on the price of the notes. In addition, if one or more rating agencies either assign the notes a rating lower than the rating expected by investors, or reduce the rating in the future, the market price of the notes would be adversely affected. If any of our other outstanding debt is rated and subsequently downgraded, raising capital will become more difficult, borrowing costs under our credit facilities and other future borrowings may increase and the market price of the notes may decrease. The credit rating agencies also evaluate the industries in which we operate as a whole and may change their credit rating for us based on their overall view of such industries.

The guarantees of the notes could be deemed fraudulent conveyances under certain circumstances, and a court may try to subordinate or void the guarantees.

Under the federal bankruptcy laws and comparable provisions of state fraudulent transfer laws, a subsidiary guarantee could be voided, or claims in respect of a subsidiary guarantee could be subordinated to all other debts of that subsidiary guarantor if, among other things, the subsidiary guarantor at the time it incurred the indebtedness evidenced by its guarantee:

In addition, any payment by that subsidiary guarantor pursuant to its guarantee of the notes could be voided and required to be returned to the subsidiary guarantor, or to a fund for the benefit of the creditors of the subsidiary guarantor. The measures of insolvency for purposes of these fraudulent transfer laws will vary depending upon the law applied in any proceeding to determine whether a fraudulent transfer has occurred. Generally, however, a subsidiary guarantor would be considered insolvent if:

If you do not properly tender your original notes, you will continue to hold unregistered notes and your ability to transfer those original notes may be adversely affected.

If you do not exchange your original notes for exchange notes in the exchange offer, you will continue to be subject to the restrictions on transfer of your original notes described in the offering memorandum distributed in connection with the private placement of the original notes. In general, you may only offer or sell the original notes if they are registered under the Securities Act and applicable state securities laws or if they are offered and sold under an exemption from those requirements. We do not plan to register the offer and resale of the original notes under the Securities Act, unless required to do so under the limited circumstances set forth in the registration rights agreement. A sale of the original notes pursuant to an exemption from the registration requirements of the Securities Act and applicable state securities law may require the delivery of an opinion of counsel to us and the registrar or co-registrar for the original notes. In addition, the issuance of the exchange notes may adversely affect the liquidity of the trading market for untendered, or tendered but unaccepted, original notes. For further information regarding the consequences of not tendering your original notes in the exchange offer, see “The Exchange Offer—Consequences of Failure to Exchange.”

We will only issue exchange notes in exchange for original notes that you timely and properly tender in the exchange offer. Therefore, you should allow sufficient time to ensure timely delivery of your original notes and other required documents to the exchange agent and you should carefully follow the instructions on how to tender your original notes. Neither we nor the exchange agent are required to tell you of any defects or irregularities with respect to your tender of original notes. We may waive any defects or irregularities with respect to your tender of original notes, but we are not required to do so and may not do so.

We are not obligated to complete the exchange offer under certain circumstances. See “The Exchange Offer—Conditions of the Exchange Offer.” Even if the exchange offer is completed, it may not be completed on the schedule described in this prospectus. Accordingly, holders participating in the exchange offer may have to wait longer than expected to receive their exchange notes.

Holders of the original notes who do not tender such notes will have no further rights under the registration rights agreement, including the right to receive special interest.

Holders who do not tender their original notes will not have any further registration rights or any right to receive special interest under the registration rights agreement or otherwise.

Some holders who exchange their original notes may be deemed to be underwriters and hence subject to subsequent transfer restrictions.

If you exchange your original notes in the exchange offer for the purpose of participating in a distribution of the exchange notes, you may be deemed to have received restricted securities and, if so, will be required to comply with the registration and prospectus delivery requirements of the Securities Act in connection with any resale transaction involving the exchange notes. See “The Exchange Offer—Purpose and Effects of the Exchange Offer” and “Plan of Distribution.”

This section of the prospectus describes the exchange offer. While we believe that the description covers the material terms of the exchange offer, this summary may not contain all of the information that is important to you. You should carefully read this entire document for a complete understanding of the exchange offer.

The purpose of the exchange offer is to satisfy our obligations under the registration rights agreement that we entered into with the initial purchasers of the original notes. We originally issued and sold $650,000,000 principal amount of original notes in a private placement on October 28, 2011 in accordance with Rule 144A and Regulation S under the Securities Act.

We are offering to exchange up to the entire $650,000,000 principal amount of original notes for a like principal amount of exchange notes.

Under the registration rights agreement, we are required, among other things, to:

In addition, under certain circumstances, we may be required to use our commercially reasonable best efforts to file a shelf registration statement to cover resales of original notes and exchange notes.

If we fail to comply with the requirements of the registration rights agreement, the interest rate on the original notes may increase. Specifically, if (i) the exchange offer registration statement is not filed within 365 days after the closing of the private placement on October 28, 2011 (or, if the exchange offer is not permitted, the shelf registration statement is not filed on or prior to the date specified for such filing) or (ii) a registration statement with respect to the original notes is filed and declared effective but thereafter ceases to be effective or fails to be usable for its intended purpose (any such event referred to in the clauses above, a “Registration Default”), the annual interest rate borne by the original notes will be increased by 0.25% per annum with respect to the first 90 days after the applicable Registration Default, and, if such default is not cured prior to the end of such 90-day period, by an additional 0.25% per annum (together with the increase described in the preceding clause, as applicable, the “Additional Interest”) with respect to each subsequent 90-day period, up to a maximum amount of additional interest of 1.0% per annum. Notwithstanding the foregoing, (i) the amount of Additional Interest payable will not increase because more than one Registration Default has occurred and is pending and (ii) a holder of original notes or exchange notes that is not entitled to the benefits of a shelf registration statement shall not be entitled to Additional Interest with respect to a Registration Default that pertains to a shelf registration statement.

We have not requested, and do not intend to request, an interpretation by the staff of the SEC with respect to whether the exchange notes may be offered for sale, resold or otherwise transferred by any holder without compliance with the registration and prospectus delivery provisions of the Securities Act. Based on interpretations by the staff of the SEC set forth in no-action letters issued to third parties, including Exxon Capital Holdings Corp. (available May 13, 1988), Morgan Stanley & Co. Incorporated (available June 5, 1991) and Shearman & Sterling (available July 2, 1993), we believe the exchange notes may be offered for resale, resold and otherwise transferred by any holder without compliance with the registration and prospectus delivery provisions of the Securities Act, provided such holder meets the following conditions:

If you do not satisfy all of the above conditions, you cannot participate in the exchange offer. Rather, in the absence of an exemption, you must comply with the registration and prospectus delivery requirements of the Securities Act in connection with a resale of the original notes. Any holder that complies with such registration and prospectus delivery requirements may incur liabilities under the Securities Act for which the holder will not be entitled to indemnification from us.

A broker-dealer that has bought original notes for its own account as part of its market-making or other trading activities must deliver a prospectus in order to resell the exchange notes it receives therefor pursuant to the exchange offer. This prospectus, as it may be amended or supplemented from time to time, may be used by a broker-dealer for such purpose, and we have agreed in the registration rights agreement to make this prospectus available to such broker-dealers upon reasonable request for the period required by the Securities Act. See “Plan of Distribution.” Each broker-dealer that receives exchange notes in the exchange offer must acknowledge that it will deliver a prospectus meeting the requirements of the Securities Act in connection with any resale of exchange notes. The accompanying letter of transmittal states that by so acknowledging and by delivering a prospectus, a broker-dealer will not be deemed to admit that it is an “underwriter” within the meaning of the Securities Act.

We are not making the exchange offer to, nor will we accept surrenders for exchange from, holders of original notes in any jurisdiction in which this exchange offer or its acceptance would not comply with applicable state securities laws or applicable laws of a foreign jurisdiction.

Participation in the exchange offer is voluntary and you should carefully consider whether to participate. We urge you to consult your financial and tax advisors in making your decision on whether to participate in the exchange offer.

Original notes that are not exchanged for exchange notes in the exchange offer will remain “restricted securities” within the meaning of Rule 144(a)(3) under the Securities Act, and will therefore continue to be subject to restrictions on transfer. Original notes will remain outstanding and will continue to accrue interest, but holders of such original notes will not be able to require us to register them under the Securities Act, except in the limited circumstances set forth in the registration rights agreement. Accordingly, following completion of the exchange offer any original notes that remain outstanding may not be offered, sold, pledged or otherwise transferred except:

In all of the situations discussed above, the resale must be in compliance with the Securities Act, any applicable securities laws of any state of the United States and any applicable securities laws of any foreign country. Any resale of original notes will also be subject to certain requirements of the registrar or any co-registrar being met, including receipt by the registrar or co-registrar of a certification and, in the case of (3), (4) and (5) above, an opinion of counsel reasonably acceptable to us and the registrar and any co-registrar.

To the extent original notes are tendered and accepted in the exchange offer, the principal amount of outstanding original notes will decrease with a resulting decrease in the liquidity in the market therefor. Accordingly, the liquidity of the market of the original notes could be adversely affected following completion of the exchange offer. See “Risk Factors—Risks Related to the Exchange Offer—If you do not properly tender your original notes, you will continue to hold unregistered notes and your ability to transfer those original notes may be adversely affected.”

Upon the terms and subject to the conditions set forth in this prospectus and in the accompanying letter of transmittal, we will accept any and all original notes validly tendered (and not withdrawn) on or prior to the Expiration Date. We will issue $1,000 principal amount of exchange notes in exchange for each $1,000 principal amount of original notes accepted in the exchange offer. The exchange notes will accrue interest on the same terms as the original notes; however, holders of the original notes accepted for exchange will not receive accrued interest thereon at the time of exchange; rather, all accrued interest on the original notes will become obligations under the exchange notes. Holders may tender some or all of their original notes pursuant to the exchange offer. However, original notes may be tendered only in denominations of $2,000 and integral multiples of $1,000 principal amount in excess thereof.

The form and terms of the exchange notes are the same as the form and terms of the original notes, except that:

The exchange notes will evidence the same debt as the original notes that they replace, and will be issued under, and be entitled to the benefits of, the indenture which governs the original notes, including the payment of principal and interest.

We are sending this prospectus and the letter of transmittal to holders of the original notes through the facilities of The Depositary Trust Company, or DTC, whose nominee, Cede & Co., is the registered holder of the original notes. The original notes are represented by permanent global notes in fully registered form, without coupons, which have been deposited with the trustee for the notes, as custodian for DTC. Ownership of beneficial interests in each global note is limited to persons who have accounts with DTC, or DTC participants, or persons who hold interests through DTC participants. The term “holder,” as used in this prospectus, means those DTC participants in whose name interests in the global notes are credited on the books of DTC, and those persons who hold interests through such DTC participants. The term “original notes,” as used in this prospectus, means such interests in the global notes. Like the original notes, the exchange notes will be deposited with the trustee for the notes as custodian for DTC, and registered in the name of Cede & Co., as nominee of DTC.

Holders of the original notes do not have any appraisal or dissenter’s rights under state law or the indenture governing the notes in connection with the exchange offer. We intend to conduct the exchange offer in accordance with the requirements of the Securities Exchange Act of 1934, as amended (the “Exchange Act”), and the SEC’s rules and regulations thereunder.

We will be deemed to have accepted validly tendered original notes when, as and if we have given written notice thereof to the exchange agent, which is Wells Fargo Bank, National Association. The exchange agent will act as agent for the tendering holders of the original notes for the purposes of receiving the exchange notes. The exchange notes delivered in the exchange offer will be issued promptly following the Expiration Date.

If any tendered original notes are not accepted for exchange because they do not comply with the procedures set forth in this prospectus and the accompanying letter of transmittal, our withdrawal of the exchange offer, the occurrence of certain other events set forth herein or otherwise, such unaccepted original notes will be returned, without expense, to the tendering holder promptly after the Expiration Date or our withdrawal of the exchange offer. Any acceptance, waiver of default or a rejection of a tender of original notes shall be at our discretion and shall be conclusive, final and binding.

Holders who tender original notes in the exchange offer will not be required to pay brokerage commissions or fees or, subject to the instructions in the letter of transmittal, transfer taxes with respect to the exchange of the original notes in the exchange offer. We will pay all charges and expenses, other than certain taxes, in connection with the exchange offer. See “—Fees and Expenses.”

The term “Expiration Date” with respect to the exchange offer means 5:00 p.m., New York City time, on July 15, 2013 unless we, in our sole discretion, extend the exchange offer, in which case the term “Expiration Date” shall mean the latest date and time to which the exchange offer is extended.

If we extend the exchange offer, we will notify the exchange agent of any extension by written notice and will make a public announcement thereof, each prior to 9:00 a.m., New York City time, no later than on the next business day after the previously scheduled Expiration Date. Any notice relating to the extension of the exchange offer will disclose the number of securities tendered as of the date of the notice, as required by Rule 14e-1(d) under the Exchange Act.

We may effect any such extension, waiver, termination or amendment by giving written notice thereof to the exchange agent.

Except as specified in the second paragraph under this heading, we will make a public announcement of any such extension, termination, amendment or waiver as promptly as practicable. If we amend or waive any condition of the exchange offer in a manner determined by us to constitute a material change to the exchange offer, we will promptly disclose such amendment or waiver in a prospectus supplement that will be distributed to the holders of the original notes. The exchange offer will then be extended for a period of five to ten business days, as required by law, depending upon the significance of the amendment or waiver and the manner of disclosure to the registered holders.

We will make a timely release of a public announcement of any extension, termination, amendment or waiver to the exchange offer to an appropriate news agency.

The exchange notes will accrue interest on the same terms as the original notes, payable semi-annually in arrears on May 15 and November 15 of each applicable year.

All of the original notes are held in book-entry form, and tenders may be made through DTC’s Book-Entry Transfer Facility or the guaranteed delivery procedures set forth below.

The exchange agent will establish an account with respect to the original notes at DTC for purposes of the exchange offer within two business days after the date of this prospectus, and any financial institution that is a participant in DTC that wishes to participate in the exchange offer may make book-entry delivery of the original notes by causing DTC to transfer such original notes into the exchange agent’s account in accordance with DTC’s procedures for such transfer. The confirmation of a book-entry transfer into the exchange agent’s account at DTC is referred to as a “Book-Entry Confirmation.” In addition, DTC participants on or before the Expiration Date must either:

The term “Agent’s Message” means a message transmitted by DTC to, and received by, the exchange agent and forming a part of the Book-Entry Confirmation, which states that DTC has received an express acknowledgment from the participant in DTC tendering the original notes that such participant has received the letter of transmittal and agrees to be bound by the terms of the letter of transmittal, and that we may enforce such agreement against such participant.

Although delivery of original notes is to be effected through book-entry at DTC, the letter of transmittal (or facsimile thereof), with any required signature guarantees, or an Agent’s Message in connection with a book-entry transfer, and any other required documents, must, in any case, be transmitted to and received by the exchange agent at one or more of its addresses set forth below on or prior to the Expiration Date, or compliance must be made with the guaranteed delivery procedures described below. Delivery of the letter of transmittal or other required documents to DTC does not constitute delivery to the exchange agent.

The tender by a holder of original notes pursuant to the procedures set forth above will constitute the tendering holder’s acceptance of all of the terms and conditions of the exchange offer. Our acceptance for exchange of original notes tendered pursuant to the procedures described above will constitute a binding agreement between such tendering holder and us in accordance with the terms and subject to the conditions of the exchange offer. Only holders are authorized to tender their original notes.

The method of delivery of original notes and letters of transmittal, any required signature guarantees and all other required documents, including delivery through DTC and any acceptance or Agent’s Message transmitted through ATOP, is at the election and risk of the persons tendering original notes and delivering letters of transmittal. If you use ATOP, you must allow sufficient time for completion of the ATOP procedures during normal business hours of DTC on or prior to the Expiration Date. Tender and delivery will be deemed made only when actually received by the exchange agent. If delivery is by mail, it is suggested that the holder use properly insured, registered mail, postage prepaid, with return receipt requested, and that the mailing be made sufficiently in advance of the Expiration Date to permit delivery to the exchange agent prior to such date.

Except as provided below, unless the original notes being tendered are delivered to the exchange agent on or prior to the Expiration Date (accompanied by a completed and duly executed letter of transmittal or a properly transmitted Agent’s Message), we may, at our option, reject the tender of such original notes. The exchange of original notes for exchange notes will be made only against the tendered original notes, which must be deposited with the exchange agent prior to or on the Expiration Date, and receipt by the exchange agent of all other required documents prior to or on the Expiration Date.

Tender of Original Notes Held Through a Nominee. If you beneficially own original notes through a bank, depository, broker, trust company or other nominee and wish to tender your original notes, you must instruct such holder to cause your original notes to be tendered on your behalf. A letter of instruction from your bank, depository, broker, trust company or other nominee may be included in the materials provided along with this prospectus, which the beneficial owner may use to instruct its nominee to effect the tender of the original notes of the beneficial owner.

Signature Guarantees. Signatures on all letters of transmittal must be guaranteed by a recognized member of the Medallion Signature Guarantee Program or by any other “eligible guarantor institution,” as that term is defined in Rule 17Ad-15 under the Exchange Act (each of the foregoing, an “Eligible Institution”), unless the original notes tendered thereby are tendered (1) by a participant in DTC whose name appears on a DTC security position listing as the owner of such original notes who has not completed either the box entitled “Special Issuance Instructions” or “Special Delivery Instructions” on the letter of transmittal, or (2) for the account of an Eligible Institution. See Instructions 5 and 6 of the letter of transmittal. If the original notes are in the name of a person other than the signer of the letter of transmittal or if original notes not accepted for exchange or not tendered are to be returned to a person other than the holder of such original notes, then the signatures on the letter of transmittal accompanying the tendered original notes must be guaranteed by an Eligible Institution as described above. See Instructions 5 and 6 of the letter of transmittal.

Guaranteed Delivery. If you wish to tender your original notes but they are not immediately available or if you cannot deliver your original notes, the letter of transmittal or any other required documents to the exchange agent or comply with the applicable procedures under ATOP prior to the Expiration Date, you may tender if:

Upon request to the exchange agent, the exchange agent will send a notice of guaranteed delivery to you if you wish to tender your original notes according to the guaranteed delivery procedures described above. See Instruction 2 of the letter of transmittal.

Determination of Validity. All questions as to the validity, form, eligibility (including time of receipt), acceptance and withdrawal of tendered original notes will be determined by us, which determination will be conclusive, final and binding. Alternative, conditional or contingent tenders of original notes will not be considered valid and may be rejected by us. We reserve the absolute right to reject any and all original notes not properly tendered or any original notes our acceptance of which, in the opinion of our counsel, would be unlawful.

We also reserve the right to waive any defects, irregularities or conditions of tender as to particular original notes. The interpretation of the terms of our exchange offer (including the instructions in the letter of transmittal) by us will be conclusive, final and binding on all parties. Unless waived, any defects or irregularities in connection with tenders of original notes must be cured within such time as we shall determine.

Although we intend to notify holders of defects or irregularities with respect to tenders of original notes through the exchange agent, neither we, the exchange agent nor any other person is under any duty to give such notice, nor shall they incur any liability for failure to give such notification. Tenders of original notes will not be deemed to have been made until such defects or irregularities have been cured or waived.

Any original notes tendered into the exchange agent’s account at DTC that are not validly tendered and as to which the defects or irregularities have not been cured or waived within the timeframes established by us in our sole discretion, if any, or if original notes are submitted in a principal amount greater than the principal amount of original notes being tendered by such tendering holder, such unaccepted or non-exchanged original notes will be credited back to the account maintained by the applicable DTC participant with such book-entry transfer facility.

Tenders of original notes in the exchange offer may be withdrawn at any time on or prior to the Expiration Date. To be effective, any notice of withdrawal must specify the name and number of the account at DTC to be credited with such withdrawn original notes and must otherwise comply with DTC’s procedures.

If the original notes to be withdrawn have been identified to the exchange agent, a signed notice of withdrawal meeting the requirements discussed above is effective immediately upon the exchange agent’s receipt of written or facsimile notice of withdrawal even if physical release is not yet effected. A withdrawal of original notes can only be accomplished in accordance with these procedures. Any failure to follow these procedures will not result in any original notes being withdrawn. We and the exchange agent may reject any withdrawal request not in accordance with these procedures.

All questions as to the validity, form and eligibility (including time of receipt) of such notices will be determined by us, which determination shall be conclusive, final and binding on all parties. No withdrawal of original notes will be deemed to have been properly made until all defects or irregularities have been cured or expressly waived. Neither we, the exchange agent nor any other person will be under any duty to give notification of any defects or irregularities in any notice of withdrawal or revocation, nor shall we or they incur any liability for failure to give any such notification. Any original notes so withdrawn will be deemed not to have been validly tendered for purposes of the exchange offer and no exchange notes will be issued with respect thereto unless the original notes so withdrawn are retendered on or prior to the Expiration Date. Properly withdrawn original notes may be retendered by following the procedures described above under “—Procedures for Tendering Original Notes” at any time on or prior to the Expiration Date.

Any original notes which have been tendered but which are not accepted for exchange due to the rejection of the tender due to uncured defects or the prior termination of the exchange offer, or which have been validly withdrawn, will be returned to the holder thereof unless otherwise provided in the letter of transmittal, promptly following the Expiration Date or, if so requested in the notice of withdrawal, promptly after receipt by us of notice of withdrawal without cost to such holder.

If we determine that any of the conditions to the exchange offer are not satisfied in accordance with their terms, we may:

If our waiver of an unsatisfied condition constitutes a material change to the exchange offer, we will promptly disclose such waiver by means of a prospectus supplement that will be distributed to the holders of the original notes, and will extend the exchange offer for a period of five to ten business days, depending upon the significance of the waiver and the manner of disclosure to the registered holders, if the exchange offer would otherwise expire during such five to ten business day period.

Wells Fargo Bank, National Association has been appointed as exchange agent for the exchange offer. The exchange agent, among other things, will not be (i) liable for any act or omission unless such act or omission constitutes its own gross negligence or willful misconduct and in no event will the exchange agent be liable to a security holder, us or any third party for special, punitive, indirect or consequential damages, including, but not limited to, lost profits, arising in connection with the exchange offer or its duties and responsibilities related to the exchange offer, (ii) obligated to take any legal action with respect to the exchange offer which might, in its judgment, involve any risk of expense, loss or liability, unless it will be furnished with indemnity satisfactory to it or (iii) liable or responsible for any statement contained in this prospectus. We will indemnify the exchange agent with respect to certain matters relating to the exchange offer.

You should direct questions and requests for assistance, requests for additional copies of this prospectus, the letter of transmittal or the notice of guaranteed delivery and requests for other documents to the exchange agent as follows:

We will bear the expenses of soliciting tenders. The principal solicitation is being made by mail by the exchange agent; however, additional solicitation may be made by telecopy, telephone or in person by our or our affiliates’ officers and regular employees.

No dealer-manager has been retained in connection with the exchange offer and no payments will be made to brokers, dealers or others soliciting acceptance of the exchange offer. However, reasonable and customary fees will be paid to the exchange agent for its services and it will be reimbursed for its reasonable out-of-pocket expenses.

Our out-of-pocket expenses for the exchange offer will include fees and expenses of the exchange agent and the trustee under the indenture governing the notes, accounting and legal fees and printing costs, among others.

We will pay all transfer taxes, if any, applicable to the exchange of the original notes pursuant to the exchange offer. If, however, exchange notes or original notes for principal amounts not tendered or accepted for exchange are to be delivered to, or are to be registered or issued in the name of, any person other than the registered holder of the original notes, or if tendered original notes are registered in the name of any person other than the person signing the letter of transmittal, or if a transfer tax is imposed for any reason other than the exchange of the original notes pursuant to the exchange offer, then the amount of any such transfer taxes (whether imposed on the tendering holder or any other persons) will be payable by the tendering holder. If satisfactory evidence of payment of such taxes or exemption therefrom is not submitted with the letter of transmittal, the amount of such transfer taxes will be billed directly to such tendering holder.

The exchange notes will be recorded at the carrying value of the original notes and no gain or loss for accounting purposes will be recognized. The expenses of the exchange offer will be amortized over the term of the exchange notes.

The exchange offer is intended to satisfy our obligations under the registration rights agreement relating to the original notes. We will not receive any proceeds from the issuance of the exchange notes in the exchange offer. In consideration for issuing the exchange notes as contemplated in this prospectus, we will receive, in exchange, outstanding original notes in like principal amount. We will cancel all original notes tendered in exchange for exchange notes in the exchange offer. The exchange notes will accrue interest on the same terms as the original notes, and all accrued interest on the original notes will become obligations under the exchange notes. As a result, the issuance of the exchange notes will not result in any increase or decrease in our indebtedness or in the early payment of interest.

The net proceeds from the sale of the original notes on October 28, 2011 were $637.0 million after discounts and directly related fees and other costs. The net proceeds were applied to pay down a portion of our affiliate debt with Chesapeake.

The following tables set forth selected historical financial data of COO and its predecessors. The selected historical financial data for each of the three-month periods ended March 31, 2013 and 2012 are derived from the unaudited condensed consolidated financial statements included elsewhere in this prospectus. The selected historical financial data for each of the years ended December 31, 2012, 2011 and 2010 are derived from the audited consolidated financial statements included elsewhere in this prospectus. The selected historical financial data for the years ended December 31, 2009 and 2008 are derived from audited 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 services operations for those periods. The summary historical financial data is 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 financial statements of COF have not been presented in this prospectus as it has had no business transactions or activities to date and has no (or nominal) assets or liabilities.

The following table sets forth our historical ratios of earnings to fixed charges on a consolidated basis for the periods indicated. You should read these ratios of earnings to fixed charges in connection with our consolidated financial statements, including the notes to those statements, included elsewhere in this prospectus. Because we did not have preferred stock outstanding during any such periods, our ratio of earnings to combined fixed charges and preferred dividends for any given period is equivalent to our ratio of earnings to fixed charges.

The following discussion and analysis of our financial condition and results of operations relate to the three months ended March 31, 2013 (the “Current Quarter”), the three months ended March 31, 2012 (the “Prior Quarter”) and the years ended December 31, 2012, 2011 and 2010 and should be read in conjunction with our consolidated financial statements and related notes appearing elsewhere in this prospectus.

Our business has grown rapidly since our first subsidiary was founded in 2001, both organically and through acquisitions. As of March 31, 2013, we owned or leased 116 land drilling rigs. As of March 31, 2013, we also operated (a) eight hydraulic fracturing fleets with an aggregate of 315,000 horsepower; (b) a diversified oilfield rentals business; (c) an oilfield trucking fleet, consisting of 286 rig relocation trucks, 67 cranes and forklifts used in the movement of drilling rigs and other heavy equipment and 254 fluid hauling trucks; and (d) manufacturing capacity for up to 150 natural gas compressor packages per quarter, or approximately 85,000 horsepower in the aggregate per quarter. We continue to modernize our asset base and have received seven of our proprietary, fit-for-purpose PeakeRigs™ that utilize advanced electronic drilling technology. We are scheduled to receive three additional PeakeRigs™ by July 2013.

Due to low natural gas prices in North America over the last few years, the oil and gas industry has experienced a shift from natural gas drilling and production towards more economical liquids-rich plays. As a result, we have seen a reduction in natural gas related activity as Chesapeake focuses on increasing liquids production, and we have experienced increased competition, near-term pricing pressure and a reduction in utilization for our services in certain markets.

We have provided substantially all of our oilfield services to Chesapeake and its working interest partners, and we expect to continue to derive a substantial majority of our revenues from Chesapeake and its working interest partners for the foreseeable future. Chesapeake’s current business strategy includes a decrease in its capital expenditure budget for 2013 from historically high levels and sales of non-core assets and assets that do not fit its long-term plans. This reduction in drilling capital expenditures has decreased Chesapeake’s utilization of many of our services. Any further reductions could have a material adverse effect on our business, financial condition and results of operations. As of March 31, 2013, Chesapeake had made a year-over-year decrease in the total number of its operated drilling rigs from 162 to 81, or 50%. Furthermore, as of March 31, 2013, Chesapeake had made a year-over-year decrease in the number of our rigs that it operates from 100 to 63, or 37%.

As part of our ongoing strategic positioning process, we continually evaluate our long-lived assets, including our drilling rig fleet, for marketability based on the specifications and condition of each evaluated asset as well as the future plans of Chesapeake. In general, demand for onshore drilling rigs in the U.S. has shifted away from less efficient mechanical drilling rigs to more efficient drilling rigs with electronic technology. As part of our drilling strategy, in addition to bringing online our newbuild PeakeRigs^TM, we have identified for retirement certain less efficient drilling rigs in our fleet. Such drilling rigs have been sold as part of our broader strategy to divest non-essential drilling rigs and make available a drilling rig fleet that is more suited to meet the future needs of Chesapeake and its working interest partners. Specifically, in August 2012, we began the process of repurchasing certain leased drilling rigs. See “—Off-Balance Sheet Arrangements.” We repurchased 25 drilling rigs for approximately $61.1 million in 2012. We incurred $10.0 million in rent expense for the year ended December 31, 2012 related to the repurchased drilling rigs. During 2012, we sold 18 drilling rigs and ancillary equipment for net proceeds of $7.4 million. The drilling rigs and equipment sold were not expected to be utilized in our business operations. In January 2013, we sold eight drilling rigs and spare equipment for cash proceeds of approximately $27.3 million.

The number of drilling rigs under contract in the U.S. decreased in 2009 but rebounded in 2010 and has remained relatively high compared 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 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 pricing fluctuations than most 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 resulted in more than $9.0 billion of drilling carries to Chesapeake.

We derive a substantial majority of 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 working interest partners, it seeks separate reimbursement of such shared costs through a joint interest billing. In addition, we perform a small amount of work for third-party customers.

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 or for a term of a certain number of days or wells. The specific terms of each request for other services are typically set forth in a field ticket or purchase or work order. The rates for the services and products we provide Chesapeake 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. As of March 31, 2013, 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 certain 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. We expect that all of our future contracts with Chesapeake and third parties will be daywork contracts. Under our services agreement that was executed in 2011, 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 its rig 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; however, there can be no assurance that any such non-utilization fee will equal or exceed the amount of revenues we could generate or the margins we could realize through normal operations. We did not receive any non-utilization fees pursuant to the agreement for the three months ended March 31, 2013 and for the years ended December 31, 2012 and 2011.

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 that was executed in 2011, 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 its stage commitment, it will be required to pay us a non-utilization fee equal to $40,000 for each committed stage not performed; however, there can be no assurance that any such non-utilization fee will equal or exceed the amount of revenues we could generate or the margins we could realize through normal operations. We did not receive any non-utilization fees pursuant to the agreement for the three months ended March 31, 2013 and for the years ended December 31, 2012 and 2011.

Oilfield Rentals Segment. We rent many types of oilfield equipment to Chesapeake and third parties, including drill pipe, drill collars, tubing, blowout preventers, frac tanks, mud tanks and environmental containment. We also provide air drilling, flowback services and services associated with the transfer of water to the wellsite for well completions. We price our rentals and services based on the type of equipment being rented and the services 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 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 our revenues from other operations from the design, engineering and fabrication of natural gas compressor packages, accessories and related equipment that we sell to Chesapeake and third parties.

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.

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.”

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 and net cash provided by operating activities, the most directly comparable GAAP financial measures, see footnote 2 to the table in “Prospectus Summary—Summary Historical Financial Data.” The table below shows our Adjusted EBITDA for the three months ended March 31, 2013 and 2012 and the years ended December 31, 2012, 2011 and 2010. Adjusted EBITDA includes $23.0 million, $26.9 million, $100.8 million, $105.6 million and $94.8 million of operating lease expenses associated with our lease of drilling rigs for the three months ended March 31, 2013 and 2012 and the years ended December 31, 2012, 2011 and 2010, respectively.

Asset utilization. We believe that our relationship and services agreement 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. 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 drilling rig utilization rate for our marketable drilling rigs was 95%, 99%, 92%, 98% and 97% for the three months ended March 31, 2013 and 2012 and the years ended December 31, 2012, 2011 and 2010, respectively.

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.

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.

On November 18, 2011, we acquired Horizon Oilfield Services, L.L.C. (“Horizon”) for $17.5 million. Included in this acquisition were 38 wellsite trailers and associated equipment, training and development programs and certain other intellectual property, and approximately 200 experienced employees.

On June 6, 2011, we acquired Bronco Drilling Company, Inc. (“Bronco”) for $339.2 million, which added 22 operating 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. (together, “Forrest”) for $84.5 million. Included in this acquisition were seven drilling rigs and related equipment.

The following table sets forth our consolidated statements of operations for the three months ended March 31, 2013 and 2012 and the years ended December 31, 2012, 2011 and 2010.

Revenues. For the Current Quarter and Prior Quarter, revenues were $543.9 million and $446.9 million, respectively. The $97.0 million increase was primarily due to substantial growth of our hydraulic fracturing business which resulted in an increase in hydraulic fracturing revenues of approximately $162.2 million, partially offset by a reduction in our average number of operating drilling rigs and a decrease in the utilization of our oilfield rental services in certain markets. Our drilling and oilfield rental segments had decreases in revenues of $67.1 million and $21.6 million, respectively, from the Prior Quarter to the Current Quarter. The vast majority of our revenues are derived from Chesapeake affiliates.

Our revenues for the three months ended March 31, 2013 and 2012 are detailed below:

Operating Costs. Operating costs for the Current Quarter and Prior Quarter were $415.0 million and $326.9 million, respectively. The increase in operating costs is due to the substantial growth of our hydraulic fracturing business, which resulted in an increase in hydraulic fracturing operating costs of approximately $131.4 million, partially offset by a reduction in our average number of operating drilling rigs and a decrease in the utilization of our oilfield rental services in certain markets. Our drilling and oilfield rental segments had decreases in operating costs of $53.8 million and $13.6 million from the Prior Quarter to the Current Quarter, respectively. As a percentage of revenues, operating costs were 76% and 73% for the Current Quarter and Prior Quarter, respectively. This increase was primarily attributable to the rapid growth of our hydraulic fracturing business, which was partially offset by a reduction in labor related costs. Our operating costs for the three months ended March 31, 2013 and 2012 are detailed below:

Depreciation and Amortization. Depreciation and amortization for the Current Quarter and Prior Quarter was $70.1 million and $53.7 million, respectively. The increase reflects the additional investments in our asset base as the result of capital expenditures. As a percentage of revenues, depreciation and amortization expense was 13% and 12% for the Current Quarter and Prior Quarter, respectively.

General and Administrative Expenses. General and administrative expenses for the Current Quarter and Prior Quarter were $20.5 million and $15.6 million, respectively. The increase was due primarily to employee retirement and other termination benefits of approximately $2.4 million and an increase in corporate overhead allocated from Chesapeake in the Current Quarter. The indirect corporate overhead covers costs of functions such as legal, accounting, treasury, environmental safety, information technology and other corporate services. The administrative expense allocation is determined by estimates of time devoted to COO entities by Chesapeake employees and Chesapeake assets utilized by COO. These charges from Chesapeake were $13.0 million and $11.2 million for the Current Quarter and Prior Quarter, respectively. As a percentage of revenues, general and administrative expenses were 4% and 3% for the Current Quarter and Prior Quarter, respectively.

Losses (Gains) on Sales of Property and Equipment. We recorded net losses (gains) on the sales of property and equipment of $0.4 million and ($1.2) million during the Current Quarter and Prior Quarter, respectively.

Impairments. We recorded impairments of a nominal amount and $1.0 million during the Current Quarter and Prior Quarter, respectively.

Interest Expense. Interest expense for the Current Quarter and Prior Quarter was $14.0 million and $12.6 million, respectively. The increase is primarily due an increase in our average outstanding long-term debt from $750.5 million to $1.063 billion, which was partially offset by a decrease in the average effective interest rate and an increase in capitalized interest. In the fourth quarter of 2011, we entered into our $500.0 million revolving bank credit facility and issued the 2019 Senior Notes. 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. For the Current Quarter and Prior Quarter, we capitalized interest of approximately $0.7 million and $0.5 million, respectively.

Losses from Equity Investees. Losses from equity investees were $0.1 million and $0.2 million for the Current Quarter and Prior Quarter, respectively, which is a result of our investments in Maalt Specialized Bulk, L.L.C. and Big Star Crude Co., L.L.C.

Other Income. Other income was $0.5 million and $0.2 million for the Current Quarter and Prior Quarter, respectively.

Income Tax Expense. We recorded income tax expense of $10.0 million and $15.4 million for the Current Quarter and Prior Quarter, respectively. The $5.4 million decrease in income tax expense recorded for the Current Quarter was primarily the result of a decrease in net income before taxes of $14.0 million from the Prior Quarter to the Current Quarter. Our effective tax rate for the Current Quarter and Prior Quarter was 41% and 40%, respectively.

Revenues. For years ended December 31, 2012, 2011 and 2010, we had revenues of $1.920 billion, $1.303 billion and $815.8 million, respectively. The increase in revenues from 2011 to 2012 was due to the start-up of our hydraulic fracturing business and the growth of most of our other services. Our hydraulic fracturing, oilfield trucking and other operations revenues increased $402.2 million, $99.2 million and $66.2 million from 2011 to 2012, respectively. The increase from 2010 to 2011 was due primarily to an increase in our revenue generating assets and, secondarily, increased drilling activity in liquids-rich plays by Chesapeake. The gross book value of our property and equipment increased 40% from December 31, 2010 to December 31, 2011. Substantially all of our revenues are derived from Chesapeake affiliates.

Our revenues for the years ended December 31, 2012, 2011 and 2010 are detailed below:

Drilling revenues for the year ended December 31, 2011 increased $282.7 million, or 49%, to $855.0 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 as demand for drilling rigs was tight. 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.

Operating Costs. Operating costs for the years ended December 31, 2012, 2011 and 2010 were $1.391 billion, $986.2 million and $667.9 million, respectively. As a percentage of revenues, operating costs were 72%, 76% and 82% for the years ended December 31, 2012, 2011 and 2010, respectively. The decrease in operating costs as a percentage of revenues is primarily attributable to improved workforce efficiency, a decrease in rig rental expense related to leased rigs and the growth of new higher margin service offerings including hydraulic fracturing and fluid handling. As a percentage of revenues, labor related costs were 28%, 35% and 37% for the years ended December 31, 2012, 2011 and 2010, respectively. As a percentage of drilling revenues, rig rental expense was 11%, 12% and 17% for the years ended December 31, 2012, 2011 and 2010, respectively. Our operating costs for the years ended December 31, 2012, 2011 and 2010 are detailed below:

Drilling operating costs for the year ended December 31, 2011 increased $201.3 million, or 42%, to $685.1 million from $483.8 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 was primarily due to the Bronco acquisition. The increase in our average number of operating rigs resulted in higher labor related 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 we experienced an increase in demand for our drilling services. As a percentage of drilling revenues, drilling operating costs decreased from 85% to 80% for the years ended December 31, 2010 and 2011, respectively. This decrease was 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. As a percentage of drilling revenues, rig rental expense decreased from 17% to 12% for the years ended December 31, 2010 and 2011, respectively.

Depreciation and Amortization. Depreciation and amortization for the years ended December 31, 2012, 2011 and 2010 was $231.3 million, $175.8 million and $103.3 million, respectively. The year-over-year 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, 2012, 2011 and 2010 were $66.4 million, $37.1 million and $25.3 million, respectively. The increase is due to hiring the majority of our senior management team in the second half of 2011 and early in 2012 and 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. The administrative expense allocation is determined by estimates of time devoted to COO entities by Chesapeake employees and Chesapeake assets utilized by COO. The indirect corporate overhead charges from Chesapeake were $49.4 million, $33.7 million and $23.9 million for the years ended December 31, 2012, 2011 and 2010, respectively.

Losses (Gains) on Sales of Property and Equipment. We recorded net losses (gains) on the sales of property and equipment of $2.0 million, ($3.6) million and ($0.9) million during the year ended December 31, 2012, 2011 and 2010, respectively.

Impairments and Other. We recorded impairments and other of $60.7 million, $2.7 million and a nominal amount for the years ended December 31, 2012, 2011 and 2010, respectively.

During the year ended December 31, 2012, we repurchased 25 leased drilling rigs for approximately $61.1 million. We recognized lease termination costs of approximately $24.9 million, which was the difference between the purchase price pursuant to the repurchase agreement and the estimated fair value of the drilling rigs. The lease termination costs are included in impairments and other on the consolidated statements of operations.

We identified four rigs during the year ended December 31, 2012 that we deemed to be impaired based on our assessment of future demand and the suitability of the identified rigs in light of this expected demand. We recorded impairment charges of $14.9 million during the year ended December 31, 2012 related to such drilling rigs with a carrying amount of $32.4 million and an estimated fair value of $17.5 million.

We also identified certain excess drill pipe that had become obsolete due to Chesapeake’s transition to liquids-focused drilling and reduced natural gas drilling. We recorded impairment charges of $7.5 million during the year ended December 31, 2012 related to such drill pipe with a carrying amount of $12.9 million and an estimated fair value of $5.4 million. We recorded additional impairments of $1.7 million, $2.7 million and a nominal amount during the years ended December 31, 2012, 2011 and 2010, respectively, related to obsolescence.

Interest Expense. Interest expense for the years ended December 31, 2012, 2011 and 2010 was $53.5 million, $48.8 million and $38.8 million, respectively. The increase from 2011 to 2012 is primarily due to an increase in our average outstanding long-term debt from $657.0 million to $873.6 million, which was partially offset by a decrease in the average effective interest rate and an increase in capitalized interest. The increase from 2010 to 2011 is primarily due to an increase in our average outstanding long-term debt from $567.1 million to $657.0 million. In the fourth quarter of 2011, we entered into a $500.0 million revolving bank credit facility and issued the 2019 Senior Notes. We used the net proceeds of $637.0 million from our 2019 Senior Notes issuance to pay down affiliate debt with Chesapeake. 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. For the years ended December 31, 2012, 2011 and 2010, we capitalized interest of approximately $2.2 million, $0.9 million and $0.6 million, respectively.

Losses from Equity Investees. Losses from equity investees were $0.4 million, $0.0 and $2.2 million for the years ended December 31, 2012, 2011 and 2010, respectively, resulting from our investments in Maalt Specialized Bulk, L.L.C., Big Star Crude Co,. L.L.C. and Resource Energy Services Corporation.

Other Income (Expense). Other income (expense) was $1.5 million, ($2.5) million and $0.2 million for the years ended December 31, 2012, 2011 and 2010, respectively.

Income Tax Expense (Benefit). We recorded income tax expense (benefit) of $46.9 million, $26.3 million and ($4.2) million for the years ended December 31, 2012, 2011 and 2010, respectively. The $20.6 million increase in income tax expense recorded for the year ended December 31, 2012 was primarily the result of an increase in net income before taxes of $62.5 million from the year ended December 31, 2011. The $30.5 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 $74.8 million.

We require capital to fund ongoing operations, including operating expenses, organic growth initiatives, investments, acquisitions and debt service. Through 2011, Chesapeake provided capital infusions to help fund our business activities. We do not anticipate receiving any future capital infusions from Chesapeake. We expect 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. See “Risk Factors—Risks Relating to Our Business—We participate in a capital intensive industry. We may not be able to finance our operations or future acquisitions.”

Our $500.0 million revolving bank credit facility is an important source of liquidity for us. The maximum amount that we may borrow under the revolving bank credit facility may be subject to limitations due to certain covenants contained in the revolving bank credit facility. As of March 31, 2013, the revolving bank credit facility was not subject to any such limitations. We are allowed to request increases in the total commitments under the revolving bank credit facility by up to $400.0 million in the aggregate, in part or in full, any time during the term of the revolving bank 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 Other Indebtedness—Revolving Bank Credit Facility.”

We have provided substantially all of our oilfield services to Chesapeake and its working interest partners. During the three months ended March 31, 2013 and 2012 and the years ended December 31, 2012, 2011 and 2010, Chesapeake and its working interest partners accounted for approximately 94%, 94%, 94%, 94% and 96% of our revenues, respectively. 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. See “Risk Factors—Risks Relating to Our Relationship with Chesapeake.”

Capital expenditures (including acquisitions) were $92.5 million, $155.2 million, $622.8 million, $752.7 million and $273.2 million for the three months ended March 31, 2013 and 2012 and the years ended December 31, 2012, 2011 and 2010, respectively.

We currently expect our growth capital expenditures to be approximately $200.0 million for 2013, and we expect to make these expenditures to grow our business lines, particularly our drilling rig and hydraulic fracturing fleets. 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.

Our cash flows depend, to a large degree, on the level of spending by Chesapeake and its working interest partners 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 three months ended March 31, 2013 and 2012 and the years ended December 31, 2012, 2011 and 2010.

The table below summarizes our cash flows for the three months ended March 31, 2013 and 2012 and the years ended December 31, 2012, 2011 and 2010:

Operating Activities. Cash provided by operating activities was $87.4 million and $6.6 million for the Current Quarter and Prior Quarter, respectively. Net income adjusted for non-cash components was approximately $94.1 million and $90.7 million for the Current Quarter and Prior Quarter, respectively. Additionally, changes in working capital items decreased cash flow provided by operating activities by $6.7 million and $84.1 million for the Current Quarter and Prior Quarter, 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, losses from equity investees and deferred income taxes.

Cash provided by operating activities was $211.2 million, $240.0 million and $94.4 million for the years ended December 31, 2012, 2011 and 2010, respectively. Net income (loss) adjusted for non-cash components was approximately $379.9 million, $233.9 million and $92.3 million for the years ended December 31, 2012, 2011 and 2010, respectively. Additionally, changes in working capital items provided (used) were ($168.7) million, $6.1 million and $2.1 million in cash flows for the years ended December 31, 2012, 2011 and 2010, respectively. The increase in cash flows used in working capital items was primarily due to extending Chesapeake’s payment terms from 30 days to 60 days in accordance with the master services agreement.

Investing Activities. Cash used in investing activities was $63.3 million and $149.9 million for the Current Quarter and Prior Quarter, respectively. Capital expenditures are the main component of our investing activities.

Cash used in investing activities was partially offset by proceeds from sales of assets in the amounts of $29.4 million and $6.7 million for the Current Quarter and Prior Quarter, respectively. In January 2013, we sold eight drilling rigs and spare equipment for cash proceeds of approximately $27.3 million.

Cash used in investing activities was $577.3 million, $658.5 million and $226.7 million for the years ended December 31, 2012, 2011 and 2010, respectively. Capital expenditures are the main component of our investing activities. Capital expenditures (including acquisitions) were $622.8 million, $752.7 million and $273.2 million for the years ended December 31, 2012, 2011 and 2010, respectively.

Cash used in investing activities was partially offset by proceeds from sales of assets in the amounts of $47.4 million, $110.9 million and $46.4 million for the years ended December 31, 2012, 2011 and 2010, 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.

In November, 2011, we acquired Horizon for $17.5 million. In June 2011, we acquired Bronco for $322.5 million, net of cash acquired, which added 22 operating drilling rigs to our rig count.

We made investments in equity investees of $1.9 million and $16.7 million in the years ended December 31, 2012 and 2011, respectively. On October 7, 2011, we entered into an agreement to acquire 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 engages in the commercial trucking business. We are committed to contribute 85% of the capital requirements of this entity. We currently own 100% of the preferred voting units, which represent a 49% ownership interest on a fully diluted basis. We will receive a preferred return (85% of all distributions) until a 25% rate of return has been reached at which time the preferred units will be converted to common units and future distributions will be based on 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.

Financing Activities. Net cash provided by (used in) financing activities was ($23.6) million and $143.8 million for the Current Quarter and Prior Quarter, respectively. We had borrowings and repayments under our $500.0 million revolving bank credit facility of $237.3 million and $247.9 million, respectively, during the Current Quarter. We had borrowings and repayments under our revolving bank credit facility of $312.6 million and $169.7 million, respectively, during the Prior Quarter.

Prior to 2012, the capital intensive nature of the oilfield services business required Chesapeake to provide regular capital infusions to fund our business activities. We do not anticipate receiving any future capital infusions from Chesapeake. Beginning in 2011, the capital infusions from Chesapeake were reported as contributions from owner. For the Current Quarter and Prior Quarter, our contributions from (distributions to) owner were ($13.0) million and $0.9 million, respectively.

Net cash provided by financing activities was $366.9 million, $418.6 million and $132.5 million for 2012, 2011 and 2010, respectively. On November 3, 2011, we entered into a five-year $500.0 million senior secured revolving bank credit facility. We had borrowings and repayments under our revolving bank credit facility of $1.389 billion and $999.9 million, respectively, during 2012. We had proceeds and repayments under our revolving bank credit facility of $168.0 million and $139.0 million, respectively, during 2011. On October 28, 2011, we issued $650.0 million principal amount of 6.625% Senior Notes due 2019 in a private placement. We used the net proceeds of $637.0 million to pay down affiliate debt with Chesapeake. We incurred $7.2 million in deferred financing costs related to our revolving bank credit facility and 2019 Senior Notes. We also made payments on third-party notes of $55.2 million during 2011. For the years ended December 31, 2012 and 2011, our contributions from (distributions to) affiliate were ($22.3) million and $453.2 million, respectively.

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 as of March 31, 2013, with projected cash payments in the years shown:

On October 1, 2011, we entered into a facilities lease agreement with Chesapeake pursuant to which we lease a number of the storage 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 is automatically renewed for successive one-year terms until we or Chesapeake terminate it. During the renewal periods, the amount of rent charged by Chesapeake increases by 2.5% each year. We make monthly payments to Chesapeake under the lease agreement that cover rent and our proportionate share of maintenance, operating expenses, taxes and insurance. These leases are being accounted for as operating leases.

As of March 31, 2013 we were a party to five lease agreements with various third parties to lease rail cars for initial terms of five to seven years. Additional rental payments are required for the use of rail cars in excess of the allowable mileage stated in the respective agreements. These leases are being accounted for as operating leases.

Aggregate undiscounted minimum future lease payments as of March 31, 2013 under our operating leases are presented below:

On October 7, 2011, we entered into an agreement to acquire 49% of the membership interests in Maalt. Under the agreement, we could be required to make future additional payments not to exceed $3.0 million which are contingent on Maalt meeting certain financial and operational performance targets. Each year in the three-year period beginning December 6, 2011, we

will determine whether Maalt has met the specified performance targets for the preceding year. In the event that Maalt has met the specified performance targets for the preceding year, we will make payments for such year based upon the number of specified performance targets met. We have accrued $0.2 million as of March 31, 2013 for future payments pursuant to this agreement.

We have also entered into a transportation services and usage agreement with Maalt under which Maalt has dedicated a portion of its trucking fleet to allow us to meet our sand transportation needs. The size of the dedicated fleet will be determined on a monthly basis based on our projected needs and agreed upon by both parties. We have guaranteed to Maalt that we will utilize its services at such a rate that the aggregate monthly revenue generated by the number of trucking units in the dedicated fleet exceeds a certain threshold stated in the agreement. If this threshold is not met during any month, we must pay Maalt an amount equal to 90% of the difference between the minimum services threshold and the total revenue generated by the trucking units during the applicable month. We have accrued $0.2 million as of March 31, 2013 for future payments pursuant to this agreement.

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.

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 major capital projects under construction using a weighted average interest rate based on our outstanding borrowings 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.

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 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 future undiscounted cash flows 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.

Goodwill represents the cost in excess of fair value of the net assets of businesses acquired. Goodwill is 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 for impairment annually on October 1 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 of. We have the option to first assess qualitative factors to determine whether the existence of events or circumstances leads to a determination that it is more likely than not that the fair value of one of our reporting units is greater than its carrying amount. If, after assessing the totality of events or circumstances, we determine it is more likely than not that the fair value of a reporting unit is greater than its carrying amount, then there is no need to perform any further testing. However, if we conclude otherwise, 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. We have the option to bypass the qualitative assessment for any reporting unit in any period and proceed directly to performing the first step of the two-step goodwill impairment test.

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. Estimated cash flows are primarily based on projected revenues, operating expenses and capital expenditures and are discounted using comparable industry average rates for weighted average cost of capital.

Substantially all of our revenues are derived from affiliates. We recognize revenue when services are performed, collection of receivables is reasonably assured, 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. Payments received and costs incurred for mobilization services are recognized as earned over the days of mobilization.

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 tanks, mud tanks and environmental containment. We also provide air drilling, flowback services and services associated with the transfer of water to the wellsite for well completions. We price our rentals and services by the day or hour based on the type of equipment rented and the services 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 handling services. Our trucks move drilling rigs, crude oil, other fluids and construction materials to and from the wellsite and also transport produced water from the wellsite. 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, accessories and related equipment that we sell to Chesapeake and third parties. We price our compression units based on certain specifications such as horsepower, stages and additional options. We recognize revenue upon completion and transfer of ownership of the natural gas compression equipment.

Chesapeake and its subsidiaries historically have filed a consolidated federal income tax return and other state returns as required. COO and its subsidiaries are limited liability companies, and as a result, 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, effective January 1, 2012 and for comparable prior periods, we have reported income taxes on a separate return basis for COO 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 as if each entity were a corporation, regardless of its actual characterization of U.S. federal income tax purposes. Any current taxes resulting from application of the separate return method will be paid in cash unless limited by the terms of our indenture and revolving credit facility, in which case such amounts will be treated as capital contribution.

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 as of March 31, 2013 and December 31, 2012.

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 three months ended March 31, 2013 and 2012 and the years ended December 31, 2012, 2011 and 2010. 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.

Historically, we have provided substantially all of our oilfield services to Chesapeake. For the three months ended March 31, 2013 and 2012 and the years ended December 31, 2012, 2011 and 2010, Chesapeake accounted for approximately 94%, 94%, 94%, 94% and 96% of our revenues, respectively. Approximately 70% of Chesapeake’s estimated proved reserves volumes as of December 31, 2012 were natural gas and 80% of Chesapeake’s 2012 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. See “Risk Factors—Risks Relating to Our Business” and “—Risks Relating to Our Relationship with Chesapeake.”

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. 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 $2.2 million increase or decrease in net income for the year ended December 31, 2012.

Our business has grown rapidly since our first subsidiary was founded in 2001, both organically and through acquisitions. As of March 31, 2013, we owned or leased 116 land drilling rigs. As of March 31, 2013, we also operated (a) eight hydraulic fracturing fleets with an aggregate of 315,000 horsepower; (b) a diversified oilfield rentals business; (c) an oilfield trucking fleet, consisting of 286 rig relocation trucks, 67 cranes and forklifts used in the movement of drilling rigs and other heavy equipment and 254 fluid hauling trucks; and (d) manufacturing capacity for up to 150 natural gas compressor packages per quarter, or approximately 85,000 horsepower in the aggregate per quarter. We continue to modernize our asset base and have received seven of our proprietary, fit-for-purpose PeakeRigs™ that utilize advanced electronic drilling technology. We are scheduled to receive three additional PeakeRigs™ by July 2013.

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

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, 2013, we owned or leased a fleet of 116 land drilling rigs, making us the fifth 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 500 to 2,000.

The following table sets forth historical information regarding utilization of our land drilling rig fleet and industry utilization rates according to RigData:

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 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 long wire rope, or drilling line, a traveling block and hook assembly and ancillary equipment that attaches to the rotating system, and 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.

Numerous factors 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 a continuing effort to improve our drilling rig fleet, 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 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 certain 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 continue to modernize our asset base and have received seven of our proprietary, fit-for-purpose PeakeRigs™ that utilize advanced electronic drilling technology. We are scheduled to receive three additional PeakeRigs™ by July 2013. These rigs 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.

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, geosteering and mud logging services in both conventional and horizontal applications to maximize drilling efficiencies and lower costs.

Drilling customers and contracts. We derive a substantial majority of 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 working interest partners, it seeks separate reimbursement of such shared costs through a joint interest billing. In addition, we perform a small amount of work for third-party customers. 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 or for a term of a certain number of days or wells. The specific terms of each request for other services are typically set forth in a field ticket or purchase or work order. The rates for the services and products we provide Chesapeake are market-based.

As of March 31, 2013, 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 certain 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. 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 its rig 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. We did not receive any non-utilization fees pursuant to the agreement for the three months ended March 31, 2013 and for the years ended December 31, 2012 and 2011.

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.

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.

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.

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 have entered into non-metallic mineral mining leases at potential sand mining sites consisting of approximately 1,900 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 wellsite, 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. 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 its stage commitment, it will be required to pay us a non-utilization fee equal to $40,000 for each committed stage not performed. We did not receive any non-utilization fees pursuant to the agreement for the three months ended March 31, 2013 and for the years ended December 31, 2012 and 2011.

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.

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.

Our oilfield trucking segment provides rig relocation and logistics services as well as fluid hauling services to Chesapeake and third party customers.

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 80 years. Our fleet includes three-axle slick-back trucks, three- and four-axle winch trucks, gin-pole trucks, tandem trucks, trailers and forklifts. We also have a fleet of heavy-duty hydraulic cranes that range in capacity from 90 to 275 tons. 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 wellsites. We operate our fluid hauling services from six facilities located in West Virginia, Pennsylvania, Oklahoma and Texas. Fluid hauling trucks are utilized in connection with drilling, completion, production and workover projects, which tend to use large amounts of various fluids, as well as the transport of crude oil. Each fluid hauling truck is equipped to pump fluids from or into wells, pits, tanks and other storage facilities. The majority of our fluid hauling trucks are 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 produced water to disposal wells or treatment facilities and to transport crude oil from the wellsite to end markets.

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, accessories and related 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 at the wellhead, throughout gathering and distribution systems, into and out of processing and storage facilities and along intrastate and interstate pipelines. We design, engineer, fabricate, sell and install natural gas compression units, accessories and equipment used in the production, treating and processing of natural gas and crude oil.

The markets in which we operate are highly competitive. Because substantially all of our operations are performed for Chesapeake and its working interest 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:

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 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.

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, services agreement and certain other agreements that we have entered into with Chesapeake and its affiliates, please see “Certain Relationships and Related Party Transactions.”

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

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

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.

Through Chesapeake, we are covered under policies of insurance that we believe are customary in the industry with customary deductibles or self-insured retentions. However, 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 or fault. For example, our master services 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) liability 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 such contractual indemnity obligations of Chesapeake arise only by applicable state law or public policy. Many states place limitations on contractual indemnity agreements, particularly agreements that indemnify a party against the consequences of its own negligence. Furthermore, certain states, including Texas, Louisiana, New Mexico and Wyoming, have enacted statutes generally referred to as “oilfield anti-indemnity acts” expressly prohibiting certain indemnity agreements contained in or related to oilfield services agreements. Such oilfield anti-indemnity acts may restrict or void a party’s indemnification of us. See “Risk Factors—Risks Relating to Our Business—Oilfield anti-indemnity provisions enacted by many states may restrict or prohibit a party’s indemnification of us.” We believe that our master services agreement with Chesapeake is structured so that any limitation on the indemnification obligations of Chesapeake imposed by state law or public policy would not materially adversely impact our liabilities under such agreement.

Our business involves the operation of heavy and powerful equipment which can result in serious injuries to our employees and third parties and substantial damage to property and the environment. 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.

We operate under the jurisdiction of a number of federal, state and local 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. See “Risk Factors—Risks Relating to Our Business.”

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.

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, such as 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.

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 (CERCLA), the Clean Water Act, the Safe Drinking Water Act, the Clean Air Act, the Resource Conservation and Recovery Act (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 solid 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.

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. In 2012, the EPA published final New Source Performance Standards (NSPS) and National Emissions Standards for Hazardous Air Pollutants (NESHAP) that amended the existing NSPS and NESHAP standards for oil and gas facilities, and created new NSPS standards for oil and gas production, transmission and distribution facilities. While these rules remain in effect, the EPA has announced that it will reexamine and reissue the rules over the next three years. Chesapeake, along with other industry groups, filed suit challenging certain provisions of the rules and is engaged in settlement negotiations to amend and correct the rules. The EPA is also conducting a review of the National Ambient Air Quality Standards for ozone that is expected to be completed in 2013. 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. See “Risk Factors—Risks Relating to Our Business.”

Hydraulic Fracturing. Vast quantities of oil, natural gas liquids and natural gas deposits exist in deep shale and other unconventional formations. It is customary in our industry to recover these resources from these deep formations through the use of hydraulic fracturing, combined with horizontal drilling. Hydraulic fracturing is the process of creating or expanding cracks, or fractures, in deep underground formations using water, sand and other additives pumped under high pressure into the formation. These formations are generally geologically separated and isolated from fresh ground water supplies by thousands of feet of impermeable 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 has asserted federal regulatory authority over hydraulic fracturing involving diesel fuels under the Safe Drinking Water Act’s Underground Injection Control Program and has released draft guidance documents regarding the process for obtaining a permit for hydraulic fracturing involving diesel fuel. While we believe that the draft guidance, if adopted as final guidance, would not materially affect our operations because we do not currently use diesel fuel in connection with our hydraulic fracturing, we cannot predict the scope or consequences of the final guidance. The EPA also has commenced a study of the potential impacts of hydraulic fracturing activities on drinking water resources, with a progress report released in late 2012 and a final draft report expected to be released for public comment and peer review in late 2014. In addition, the Bureau of Land Management (BLM) has announced its intention to publish, in the first quarter of 2013, a revised draft of proposed rules that would impose new requirements on hydraulic fracturing operations conducted on federal lands, including the disclosure of chemical additives used. The results of the EPA’s guidance, including its definition of diesel fuel, the EPA’s study, the BLM’s proposed rules and other analyses by federal and state agencies to assess the impacts of hydraulic fracturing could each spur further action towards federal and/or state legislation and regulation of hydraulic fracturing activities.

Also, 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 to 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 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 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 announced their intent to propose coordinated rules to regulate greenhouse gas emissions from heavy-duty engines and vehicles, and light-duty vehicles. 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.

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. See “Risk Factors—Risks Relating to Our Business—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.”

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.

Chesapeake Oilfield Operating, L.L.C. (“COO”) is an indirect, wholly owned subsidiary of Chesapeake. Chesapeake manages and conducts the business of COO through its wholly owned subsidiaries, Chesapeake Operating, Inc. (“COI”) and COS Holdings, L.L.C. (“COS LLC”). Each of COS LLC and COO is a manager-managed limited liability company. As sole manager of COS LLC, COI has the authority to manage and conduct the business of COS LLC, which, as sole manager of COO, in turn has the authority to manage and conduct the business of COO. Chesapeake Oilfield Finance, Inc. (“COF”) is a wholly owned subsidiary of COO and was incorporated for the purpose of facilitating the offering of the notes. COF does not and will not have any operations or revenues. Each of COI and COF has a two-member Board of Directors as further described below.

The following table sets forth certain information regarding the executive officers, directors and certain significant employees of COO, COF and COS LLC. Additionally, the directors and certain executive officers of COI are included below because such individuals are involved in the management of COO.

Each of Messrs. Dixon and Dell’Osso received his entire compensation from Chesapeake and received no separate compensation for his service to us. On May 20, 2013, Chesapeake announced that Robert Douglas (“Doug”) Lawler, Senior Vice President, International and Deepwater Operations at Anadarko Petroleum, will join Chesapeake as Chief Executive Officer and a member of the Board of Directors of Chesapeake, effective June 17, 2013. We anticipate that Mr. Lawler will also be appointed as Chief Executive Officer of COI and a member of the Board of Directors of COI and COF, respectively, replacing Mr. Dixon in such roles.

Jerry L. Winchester has served as Chief Executive Officer of COO and COS LLC since September 2011, and as Chief Executive Officer of COF since October 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 has served as Chief Financial Officer of COO, COF and COS LLC 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 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 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 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 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 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 compression services to Chesapeake and third parties, 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.

Steven C. Dixon has served as Acting Chief Executive Officer of Chesapeake since April 1, 2013 and currently is a member of the Board of Directors of COI and COF. In addition, he 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 from 1995 to 2006. He also served as Vice President—Exploration of Chesapeake from 1991 to 1995.

Domenic J. (“Nick”) Dell’Osso, Jr. has served as Executive Vice President and Chief Financial Officer of Chesapeake since November 2010 and currently is a member of the Board of Directors of COI and COF. In addition, Mr. Dell’Osso has also served as a director of the general partner of Access Midstream Partners, L.P. 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.

Chesapeake Oilfield Operating, L.L.C., an indirect, wholly owned subsidiary of Chesapeake, does not have any securities listed on a national securities exchange or on an inter-dealer quotation system and therefore is not subject to a number of the corporate governance requirements of the SEC or of any national securities exchange or inter-dealer quotation system. For example, COO is not required to have a board of directors comprised of a majority of independent directors or to have an audit committee comprised of independent directors. Accordingly, COO has not made any determination as to whether it would qualify as independent under the listing standards of any national securities exchange or any inter-dealer quotation system or under any other independence definition.

COS LLC and COO entered into the following affiliate transactions with Chesapeake in connection with the establishment of COS LLC’s business in October 2011. The description of each agreement set forth below does not purport to be complete and is qualified in its entirety by reference to the full text of each such 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.

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 rig 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; however, 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.

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.

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.

As an indirect, wholly owned subsidiary of Chesapeake, we are subject to Chesapeake’s written policy regarding related party transactions. Chesapeake has adopted written policies and procedures for review, by the Audit Committee of Chesapeake’s Board of Directors, of any transaction, arrangement or relationship or series of similar transactions, arrangements or relationships (including any indebtedness or guarantee of indebtedness) in which (1) the aggregate amount involved will or may be expected to exceed $120,000 in any calendar year, (2) Chesapeake or a subsidiary is a participant and (3) any of its directors, executive officers, or greater than 5% shareholders, or any of their immediate family members, has or will have a material direct or indirect interest. The Audit Committee approves or ratifies only those transactions that it determines in good faith are in, or are not inconsistent with, the best interests of Chesapeake and its shareholders.

In this section, we describe the material components of Chesapeake Energy Corporation’s executive compensation program which is used for its named executive officers (NEOs). We expect that our compensation program will be designed by Chesapeake with similar goals and objectives. We are an indirect, wholly owned subsidiary of Chesapeake, and the Compensation Committee of Chesapeake’s Board of Directors oversees our executive compensation policies and practices. Thus, historical compensation information presented in this section reflects the policies and procedures of, and decisions made by, Chesapeake. We also provide an overview of Chesapeake’s executive compensation philosophy and of important changes Chesapeake recently implemented to its executive compensation program. The following is a description and explanation of the compensation program for the following persons that served as COO’s NEOs during 2012. Each person listed below also served COF in a corresponding position.

Chesapeake implemented substantial changes to its executive compensation program in 2012, including redesigning its annual and long-term incentive programs so that they are based on objective performance criteria and appropriately tie pay to performance. Chesapeake’s 2012 redesigned, performance-based executive compensation program reflects the Compensation Committee’s intent to generally set all elements of target compensation at the median of similarly-situated executives among Chesapeake’s peer group or other relevant industry benchmarks. The competitive positioning of target compensation levels for individuals may vary above or below the median based on executive-specific factors such as tenure, experience, proficiency in role or criticality to the organization. The Compensation Committee’s objective is to have a program that:

Unlike target compensation levels, which are set by the Compensation Committee near the beginning of the year, actual compensation is a function of Chesapeake’s operating, financial and stock price performance, as reflected through annual incentive payouts, performance share payouts and the value of all other long-term incentive awards at vesting. Actual compensation is intended to vary above or below target commensurate with Chesapeake’s performance.

The purpose and key characteristics of each element of Chesapeake’s 2012 executive compensation program are summarized below:

Base salaries reflect each NEO’s base level of responsibility, leadership, tenure and contribution to the success and profitability of Chesapeake and the competitive marketplace for executive talent specific to our industry.

The annual incentive program (AIP) component of Chesapeake’s executive compensation system is intended to motivate and reward NEOs for achieving short-term business objectives that we believe drive the overall performance of the company over the long term. In 2012, the Compensation Committee focused heavily on redesigning Chesapeake’s annual incentive program, implementing a formulaic approach to awarding annual incentives based on an objective evaluation of the company’s performance relative to seven pre-established, objective operational and financial goals. Mr. Baetz did not participate in the AIP in 2012.

Long-term incentive compensation increases shareholder value by aligning the interests of the NEOs with Chesapeake’s shareholders. In 2012, the Compensation Committee approved significant modifications to Chesapeake’s long-term incentive compensation program, incorporating performance share unit (PSU) awards under the long-term incentive plan (LTIP) to the mix of long-term incentive compensation. Total compensation for NEOs is weighted heavily toward long-term incentive compensation. This approach is intended to motivate our NEOs to achieve our business objectives by tying incentives to our financial performance and key operational performance objectives over the performance periods and continue to reinforce the link between the interests of our NEOs and our shareholders. Mr. Baetz was not eligible to receive PSU awards in 2012.

Chesapeake also provides compensation in the form of personal benefits and perquisites to NEOs, including health and welfare insurance benefits, matching contributions of common stock under the company’s 401(k) Plan and Nonqualified Deferred Compensation Plan (DCP) (up to 15% of an employee’s annual base salary and cash bonus compensation) and financial planning services.

The following compensation discussion and analysis is complete with respect to compensation provided by us to our NEOs for their service to us, but it does not purport to be a complete discussion and analysis with respect to Chesapeake’s executive compensation disclosure. Our NEOs received no separate compensation from Chesapeake.

The table below summarizes the compensation received by our NEOs in 2012. The NEOs did not receive any option awards and do not participate in a pension plan.

The table below summarizes grants of plan-based awards made to our NEOs under Chesapeake’s equity and non-equity incentive plans during 2012.

The table below contains information regarding unvested equity awards held by our NEOs under Chesapeake’s equity compensation plans as of December 31, 2012.

None of our NEOs held any options to purchase Chesapeake’s common stock or shares of Chesapeake’s restricted common stock that vested during 2012.

Neither we nor Chesapeake has a pension plan or any other retirement plan other than the Chesapeake 401(k) Plan and the DCP.

The NEOs are permitted to participate in the DCP. The DCP allows certain employees to voluntarily defer receipt of a portion of their salary and/or their semi-annual bonus payments. Pursuant to the terms of the administrative services agreement, a portion of the expense related to these plans is allocated to us by Chesapeake.

Chesapeake maintains the Chesapeake Energy Corporation Amended and Restated Deferred Compensation Plan, or the DCP, a nonqualified deferred compensation plan. In 2012, Chesapeake matched employee-participant contributions to the DCP, on a quarterly basis in arrears, in Chesapeake’s common stock (or other form of matching contribution at the election of employee-participants age 55 or older) dollar for dollar for up to 15% of the employee-participant’s base salary and bonus in the aggregate for the 401(k) Plan and the DCP. Each quarterly matching contribution to the DCP vests at the rate of 25% per year over four years from the date of each contribution. At age 55 with at least 10 years of service with the company, unvested and future matching contributions may be subject to accelerated vesting, in Chesapeake’s sole discretion.

Participant contributions to the DCP are held in “Rabbi trusts.” Notional earnings on participant contributions are credited to each participant’s account based on the market rate of return of the available benchmark investment alternatives offered under the DCP. The benchmark investments are indexed to traded mutual funds and each participant allocates his or her contributions among the investment alternatives. Participants may change the asset allocation of their contribution balance or make changes to the allocation for future contributions at any time. Any unallocated portion of a participant’s account is deemed to be invested in the money market fund.

Employees participating in the DCP who retire or terminate employment after attainment of age 55 with at least 10 years of service can elect to receive distributions of their vested account balances in full or partial lump sum payments or in installments up to a maximum of 20 annual payments. Upon retirement or termination of employment prior to the attainment of age 55 and at least 10 years of service with the company, the employee will receive his or her entire account balance in a single lump sum. Participants can modify the distribution schedule for a retirement/termination distribution from lump sum to annual installments or from installments to lump sum if such modification requires that payments commence at least five years after retirement/termination and the modification is filed with the plan administrator at least twelve months prior to retirement/termination. Distributions from the DCP upon the death of a participant will be made in a single lump sum and upon a participant’s disability, as defined in the DCP, based on the participant’s retirement/termination distribution election. Chesapeake has sole discretion to accelerate vesting of unvested company matching contributions upon a participant’s retirement, death or disability.

Any assets placed in trust by the company to fund future obligations of the DCP are subject to the claims of creditors in the event of insolvency or bankruptcy, and participants are general creditors of the Company as to their deferred compensation in the DCP.

Each of our NEOs is party to an employment agreement that governs the terms and conditions of his employment, including his duties and responsibilities, compensation and benefits, and applicable severance terms. The energy industry’s history of

terminating professionals during its cyclical downturns and the frequency of mergers, acquisitions and consolidation in our industry are two important factors that have contributed to a widespread, heightened concern for long-term job stability by many professionals in our industry. In response to this concern, arrangements that provide compensation guarantees in the event of an employee’s termination without cause, death or incapacity or due to a change of control are common practice in our industry. These provisions in the NEOs’ employment agreements and the incentive plans in which the NEOs participate are integral to our ability to recruit and retain the high caliber of professionals that are critical to the successful execution of our business strategy. Below is a discussion of these arrangements.

Mr. Winchester. If Mr. Winchester’s employment is terminated without cause or if Mr. Winchester terminates his employment for good reason, Mr. Winchester is entitled to receive the following payments and benefits:

Mr. Baetz. If Mr. Baetz’s employment is terminated without cause or if Mr. Baetz terminates his employment for good reason, Mr. Baetz is entitled to receive the following payments and benefits:

Mr. Winchester. Upon a change of control of Chesapeake, Mr. Winchester is entitled to a payment in an amount equal to 200% of the sum of (a) his base salary as of the date of the change of control and (b) bonus compensation paid to him during the twelve-month period immediately prior to the change of control. In addition, all unvested Chesapeake equity awards granted under his employment agreement and supplemental matching contributions to the DCP will immediately vest.

Mr. Baetz. Upon a change of control of Chesapeake, Mr. Baetz is entitled to a payment in an amount equal to 100% of the sum of (a) his base salary as of the date of the change of control and (b) bonus compensation paid to him during the twelve-month period immediately prior to the change of control. In addition, all Chesapeake restricted common stock granted under his employment agreement and supplemental matching contributions to the DCP will immediately vest.

A “change of control” is defined in the employment agreements to include the occurrence of any of the following:

If a NEO’s employment is terminated due to the executive’s incapacity or death, the executive (or his beneficiary or estate, as applicable) is entitled to receive:

The tables below quantify the payments and benefits due to Messrs. Winchester and Baetz in the event of a qualifying termination of employment and/or in the event of a change of control of Chesapeake.

The amounts disclosed in the table below assume that the termination event and/or the occurrence of the change of control occurred on December 31, 2012. We have also assumed that each NEO (a) was employed from January 1, 2012 through December 31, 2012, (b) had no accrued paid time off as of December 31, 2012 and (c) was awarded only the shares of Chesapeake restricted common stock and PSUs that they were actually awarded in 2012. In calculating the bonus payments in the table below, we have used the applicable minimum annual bonus specified in the executive’s employment agreement. The actual amounts to be paid are dependent on various factors, which may or may not exist at the time a NEO is actually terminated or a change of control actually occurs.

In addition to the amounts shown above, the NEOs would have been entitled to receive the distributions reflected in the Aggregate Balance at Last Fiscal Year-End column of the Nonqualified Deferred Compensation Table for 2012 (payments of which may be deferred to satisfy the provisions of Section 409A or made over time pursuant to individual elections).

The following table sets forth, as of December 31, 2012, the number of shares of common stock of Chesapeake Energy Corporation owned by each of our executive officers and all of our 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.

In November 2011, we, as borrower, and all of our material subsidiaries (other than Chesapeake Oilfield Finance, Inc.), as guarantors, entered into a $500.0 million senior secured revolving bank credit facility with Bank of America, N.A. (“Bank of America”) as administrative agent and collateral agent. The revolving bank credit facility matures on November 3, 2016.

The revolving bank 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 bank credit facility, with any such increases being subject to certain requirements as well as lenders’ approval.

Amounts borrowed under the revolving bank credit facility are secured by liens on all of our equity interests and that of our current and future guarantor subsidiaries, and all of our and our guarantor subsidiaries’ assets, including real and personal property. During any period that we maintain an investment grade corporate rating, the requirements that we provide security for amounts borrowed under the facility will be suspended.

Borrowings bear interest under a leverage-based pricing grid at our option at either: (a) the greater of (1) the reference rate of Bank of America, (2) the federal funds effective rate plus 0.50% or (3) the Eurodollar rate, which is based on the London Interbank Offered Rate (LIBOR), plus 1.00%, each of which is subject to a margin that varies from 1.00% to 1.75% per annum, according to our leverage ratio, or (b) the Eurodollar rate plus a margin that varies from 2.00% to 2.75% per annum, according to our leverage ratio. The unused portion of the revolving bank credit facility is subject to commitment fees of 0.375% to 0.500% per annum, according to our leverage ratio. Interest is payable quarterly or, if LIBOR applies, it may be payable at more frequent intervals.

The revolving bank credit facility contains covenants requiring us to maintain certain financial ratios such as leverage and fixed charge cover. In addition, the revolving bank credit facility includes negative covenants that, subject to exceptions, limit our and each of our subsidiaries’ ability to, among other things:

The revolving bank credit facility contains certain customary representations and warranties, affirmative and negative covenants and events of default, including, among other things, payment defaults, breaches of representations and warranties, covenant defaults, cross-defaults to material indebtedness, certain events of bankruptcy, certain events under ERISA, material judgments, actual or asserted failure of any guaranty or security document supporting the credit facility to be in force and effect and change of control. If an event of default occurs, the administrative agent is entitled to take various actions, including the acceleration of amounts due under the credit facility, termination of the commitments under the revolving bank credit facility and all remedial actions available to a secured creditor.

On October 28, 2011, we issued $650.0 million aggregate principal amount of 6.625% Senior Notes due 2019, or the “original notes,” under an Indenture dated October 28, 2011 (the “Indenture”), among us, the Subsidiary Guarantors and The Bank of New York Mellon Trust Company, N.A., as trustee, in a private transaction that was not subject to the registration requirements of the Securities Act.

As part of our sale of the original notes, we are required, among other things, to complete this exchange offer, offering to exchange the original notes for new registered 6.625% Senior Notes due 2019, or the “exchange notes.” The exchange notes are substantially identical to the original notes, except the exchange notes are registered under the Securities Act, and the transfer restrictions and registration rights, and related special interest provisions applicable to the original notes will not apply to the exchange notes. The exchange notes will represent the same debt as the original notes and we will issue the exchange notes under the Indenture. The terms of the original notes and the exchange notes include those stated in the Indenture and those made part of the Indenture by reference to the Trust Indenture Act of 1939, as amended, or the “TIA.” The original notes and the exchange notes are collectively referred to herein as the “Notes” or “notes.” Copies of the Indenture may be obtained from us upon request.

The following summary of certain provisions of the Indenture and the notes does not purport to be complete and is subject to, and is qualified in its entirety by reference to, all of the provisions of the Indenture, including the definitions of certain terms therein and those terms made a part thereof by the TIA. Capitalized terms used in this “Description of Exchange Notes” section and not otherwise defined have the meanings set forth in the section “—Certain Definitions.” As used in this “Description of Exchange Notes” section, the terms “we,” “us” and “our” mean Chesapeake Oilfield Operating, L.L.C. (“COO”) and not any of its subsidiaries. The term “Issuers” means COO and Chesapeake Oilfield Finance, Inc. (“COF”), a wholly owned subsidiary of COO, and not any of their respective subsidiaries.

We will issue the exchange notes solely in exchange for an equal principal amount of outstanding original notes. As of the date of this prospectus, $650.0 million aggregate principal amount of original notes are outstanding. We may issue additional notes from time to time without notice or the consent of holders of notes. Any offering of additional notes is subject to the covenants described below under the captions “—Certain Covenants—Incurrence of Indebtedness and Issuance of Preferred Stock” and “—Certain Covenants—Liens.” The notes and any additional notes subsequently issued under the Indenture will be treated as a single class for all purposes under the Indenture, including, without limitation, waivers, amendments, redemptions and offers to purchase. Except as otherwise specified herein, all references to the “Notes” or “notes” include additional notes.

Principal, premium, if any, and interest on the notes will be payable, and the notes may be exchanged or transferred, at the office or agency of the Issuers as specified in the Indenture (which initially shall be the principal corporate trust office of the Paying Agent).

The exchange notes will be issued only in fully registered form, without coupons, in denominations of $2,000 and any integral multiple of $1,000 in excess thereof. No service charge will be made for any registration of transfer or exchange of exchange notes, but the Issuers may require payment of a sum sufficient to cover any transfer tax or other similar governmental charge payable in connection therewith.

The Notes are guaranteed by all of COO’s existing Subsidiaries, other than certain immaterial Subsidiaries.

The obligation of our newly created or acquired Subsidiaries to guarantee the Notes is described below under “—Certain Covenants—Additional Subsidiary Guarantees.” In the event of a bankruptcy, liquidation or reorganization of any non-guarantor Subsidiary, the non-guarantor Subsidiary will pay the holders of its debt and its trade creditors before it will be able to distribute any of its assets to us.

As of the date of the Indenture, all of our Subsidiaries were “Restricted Subsidiaries.” However, under the circumstances described below under “—Certain Covenants—Designation of Restricted and Unrestricted Subsidiaries,” we will be permitted to designate certain of our Subsidiaries as “Unrestricted Subsidiaries.” Our Unrestricted Subsidiaries will not be subject to most of the restrictive covenants in the Indenture and will not guarantee the Notes.

Interest on the Notes will accrue at the rate of 6.625% per annum and is payable semi-annually in arrears on May 15 and November 15, which commenced on May 15, 2012. The Issuers will make each interest payment to the Holders of record on the May 1 and November 1 immediately preceding the relevant interest payment date.

Interest on the Notes will accrue from the date of original issuance or, if interest has already been paid, from the date it was most recently paid. Interest will be computed on the basis of a 360-day year consisting of twelve 30-day months.

If a Holder has given wire transfer instructions to the Issuers, the Issuers will pay all principal, interest and premium, if any, on that Holder’s Notes in accordance with those instructions. All other payments on Notes will be made at the office or agency of the paying agent and registrar within the City and State of New York unless the Issuers elects to make interest payments by check mailed to the Holders at their addresses set forth in the register of Holders.

The trustee will initially act as paying agent and registrar. The Issuers may change the paying agent or registrar without prior notice to the Holders of the Notes, and COO or any of its Subsidiaries may act as paying agent or registrar.

A Holder may transfer or exchange Notes in accordance with the Indenture. The registrar and the trustee may require a Holder to furnish appropriate endorsements and transfer documents in connection with a transfer of Notes. No service charge will be imposed by the Issuers, the trustee or the registrar for any registration of transfer or exchange of Notes, but Holders will be required to pay all taxes due on transfer. The Issuers are not required to transfer or exchange any Note selected for redemption. Also, the Issuers are not required to transfer or exchange any Note for a period of 15 days before a selection of Notes to be redeemed.

COF is a wholly owned subsidiary of COO and was incorporated in October 2011 for the purpose of facilitating the offering of Notes. COF is nominally capitalized at $1,000 and does not and will not have any operations or revenues. As a result, prospective purchasers of the Notes should not expect COF to participate in servicing the interest and principal obligations on the Notes. See “—Certain Covenants—Restrictions on Activities of COF.”

All of COO’s existing Subsidiaries, other than certain immaterial Subsidiaries, have guaranteed the Notes on a senior unsecured basis. In the future, other Restricted Subsidiaries of COO will be required to guarantee the Notes under the circumstances described under “—Certain Covenants—Additional Subsidiary Guarantees.” These Subsidiary Guarantees will be joint and several obligations of the Subsidiary Guarantors. The obligations of each Subsidiary Guarantor under its Subsidiary Guarantee will be limited as necessary to prevent that Subsidiary Guarantee from constituting a fraudulent conveyance under applicable law. See “Risk Factors—Risks Related to the Notes—The guarantees of the notes could be deemed fraudulent conveyances under certain circumstances, and a court may try to subordinate or void the guarantees.”

The Subsidiary Guarantee of a Subsidiary Guarantor automatically will be released:

(1) in connection with any sale or other disposition of all or substantially all of the properties or assets of that Subsidiary Guarantor (including by way of merger or consolidation) to a Person that is not (either before or after giving effect to such transaction) a Restricted Subsidiary of COO, if the sale or other disposition does not violate the “Asset Sale” provisions of the Indenture;

(2) in connection with any sale or other disposition of Capital Stock of that Subsidiary Guarantor to a Person that is not (either before or after giving effect to such transaction) a Restricted Subsidiary of COO, if the sale or other disposition does not violate the “Asset Sale” provisions of the Indenture and the Subsidiary Guarantor ceases to be a Restricted Subsidiary of COO as a result of such sale or other disposition;

(3) if COO designates that Subsidiary Guarantor as an Unrestricted Subsidiary in accordance with the applicable provisions of the Indenture;

(4) upon Legal Defeasance or Covenant Defeasance as described below under “—Legal Defeasance and Covenant Defeasance” or upon satisfaction and discharge of the Indenture as described below under “—Satisfaction and Discharge;” or

(5) in the case of any Subsidiary Guarantor, at such time as such Subsidiary Guarantor ceases to be directly liable for, or guarantee any other Indebtedness of COO or any Restricted Subsidiary, in an aggregate amount in excess of $15.0 million.

Except as provided below, the Notes will not be redeemable at the Issuers’ option prior to November 15, 2015.

On and after November 15, 2015, the Issuers may on one or more occasions redeem all or a part of the Notes, at the redemption prices (expressed as percentages of principal amount) set forth below, plus accrued and unpaid interest, if any, on the Notes redeemed to the applicable redemption date (subject to the right of Holders of record on the relevant record date to receive interest due on an interest payment date that is on or prior to the redemption date), if redeemed during the twelve-month period beginning on November 15 of the years indicated below:

At any time prior to November 15, 2014, the Issuers may on one or more occasions redeem up to 35% of the aggregate principal amount of Notes issued under the Indenture at a redemption price of 106.625% of the principal amount, plus accrued and unpaid interest, if any, to the redemption date (subject to the right of Holders of record on the relevant record date to receive interest due on an interest payment date that is on or prior to the redemption date), with the net cash proceeds of one or more Equity Offerings by COO (or COO’s direct parent company, to the extent such net cash proceeds are contributed to COO), provided that:

(1) at least 65% of the aggregate principal amount of Notes issued under the Indenture on the Initial Issuance Date remains outstanding immediately after the occurrence of such redemption (excluding Notes held by COO and its Subsidiaries);

(2) the redemption occurs within 120 days of the date of the closing of such Equity Offering; and

(3) such redemption shall not be applicable to or part of any transaction that results in, relates to, is made in connection with, or is made in contemplation of, a Change of Control.

Prior to November 15, 2015, the Issuers may on one or more occasions redeem all or part of the Notes at a redemption price equal to the sum of:

plus accrued and unpaid interest, if any, to the redemption date (subject to the right of Holders of record on the relevant record date to receive interest due on an interest payment date that is on or prior to the redemption date).

“Make Whole Premium” means, with respect to a Note on any applicable redemption date, the excess, if any, of (a) the present value at such time of (i) the redemption price of such Note at November 15, 2015, (set forth in the table above) plus (ii) any required interest payments due on such Note through November 15, 2015, (except for currently accrued and unpaid interest), computed using a discount rate equal to the Treasury Rate plus 50 basis points, discounted to the redemption date on a semi-annual basis (assuming a 360-day year consisting of twelve 30-day months), over (b) the principal amount of such Note.

“Treasury Rate” means the yield to maturity at the time of computation of United States Treasury securities with a constant maturity (as compiled and published in the most recent Federal Reserve Statistical Release H.15(519) which has become publicly available at least two Business Days prior to the date fixed for redemption (or, if such Statistical Release is no longer published, any publicly available source of similar market data)) most nearly equal to the period from the redemption date to November 15, 2015; provided, however, that if such period is not equal to the constant maturity of a United States Treasury security for which a weekly average yield is given, the Issuers shall obtain the Treasury Rate by linear interpolation (calculated to the nearest one-twelfth of a year) from the weekly average yields of United States Treasury securities for which such yields are given, except that if the period from the redemption date to November 15 , 2015, is less than one year, the weekly average yield on actually traded United States Treasury securities adjusted to a constant maturity of one year shall be used. The Issuers will calculate the Treasury Rate no later than the second Business Day preceding the applicable redemption date and prior to such redemption date file with the trustee an officers’ certificate setting forth the Make Whole Premium and the Treasury Rate.

If less than all of the Notes are to be redeemed at any time, the trustee will select Notes for redemption as follows:

(1) if the Notes are listed on any national securities exchange, in compliance with the requirements of the principal national securities exchange on which the Notes are listed; or

(2) if the Notes are not listed on any national securities exchange, on a pro rata basis.

No Notes of $2,000 or less can be redeemed in part. Notices of optional redemption will be mailed by first class mail at least 30 but not more than 60 days before the redemption date to each Holder of Notes to be redeemed at its registered address, except that optional redemption notices may be mailed more than 60 days prior to a redemption date if the notice is issued in connection with a defeasance of the Notes or a satisfaction and discharge of the Indenture. Notices of redemption may not be conditional, except that any redemption described in the third paragraph under “—Optional Redemption” may, at the Issuers’ discretion, be subject to completion of the related Equity Offerings.

If any Note is to be redeemed in part only, the notice of redemption that relates to that Note will state the portion of the principal amount of that Note that is to be redeemed. A new Note in principal amount equal to the unredeemed portion of the original Note will be issued in the name of the Holder of Notes upon cancellation of the original Note. Notes called for redemption become due on the date fixed for redemption. On and after the redemption date, interest ceases to accrue on Notes or portions of them called for redemption.

Except as set forth below under “—Repurchase at the Option of Holders,” the Issuers are is not required to make mandatory redemption or sinking fund payments with respect to the Notes or to repurchase the Notes at the option of the Holders.

If a Change of Control occurs, each Holder of Notes will have the right to require COO to repurchase all or any part (equal to $2,000 or an integral multiple of $1,000 in excess thereof) of that Holder’s Notes pursuant to an offer on the terms set forth in the Indenture (the “Change of Control Offer”). In the Change of Control Offer, COO will offer a payment in cash equal to 101% of the aggregate principal amount of Notes repurchased plus accrued and unpaid interest, if any, on the Notes repurchased, to the date of purchase (the “Change of Control Payment”). Within 30 days following any Change of Control, COO will mail to each Holder a notice describing the transaction or transactions that constitute the Change of Control and offering to repurchase Notes on the date specified in the notice, which date will be no earlier than 30 days and no later than 60 days from the date such notice is mailed (the “Change of Control Payment Date”), pursuant to the procedures required by the Indenture and described in such notice.

(1) accept for payment all Notes or portions of Notes properly tendered pursuant to the Change of Control Offer;

(2) deposit with the paying agent an amount equal to the Change of Control Payment in respect of all Notes or portions of Notes properly tendered; and

(3) deliver or cause to be delivered to the trustee the Notes properly accepted together with an officers’ certificate stating the aggregate principal amount of Notes or portions of Notes being purchased by COO.

The paying agent will promptly mail to each Holder of Notes so tendered and not withdrawn the Change of Control Payment for such Notes (or, if all the Notes are then in global form, make such payment through the facilities of DTC), and the trustee will authenticate and mail (or cause to be transferred by book entry) to each Holder a new Note equal in principal amount to

any unpurchased portion of the Notes surrendered, if any, by such Holder; provided that each new Note will be in a minimum principal amount of $2,000 or an integral multiple of $1,000 in excess thereof. If the Change of Control Payment Date is on or after an interest payment record date and on or before the related interest payment date, any accrued and unpaid interest will be paid to the Person in whose name a Note is registered at the close of business on such record date, and no other interest will be payable to Holders who tender pursuant to the Change of Control Offer.

COO will publicly announce the results of the Change of Control Offer on or as soon as practicable after the Change of Control Settlement Date.

If we fail to repurchase all of the Notes tendered for purchase upon a Change of Control, such failure will constitute an Event of Default. In addition, if a Change of Control occurs, we may not be able to obtain the consents necessary to consummate a Change of Control Offer from the lenders under agreements governing outstanding Indebtedness which may prohibit the offer. Moreover, the occurrence of certain of the events which would constitute a Change of Control may constitute an event of default under the Credit Agreement and may constitute an event of default under future Indebtedness. Finally, the exercise by the Holders of their right to require COO to purchase the Notes could cause a default under such Indebtedness, even if the Change of Control itself does not, due to the financial effect of the repurchase on COO.

The provisions described above that require COO to make a Change of Control Offer following a Change of Control will be applicable regardless of whether or not any other provisions of the Indenture are applicable. Except as described above with respect to a Change of Control, the Indenture does not contain provisions that permit the Holders of the Notes to require that COO repurchase or redeem the Notes in the event of a takeover, recapitalization or similar transaction. Subject to our compliance with the other covenants described below under “—Other Covenants,” we could, in the future, enter into certain transactions, including acquisitions, refinancings or other recapitalizations, that would not constitute a Change of Control under the Indenture, but that could increase the amount of Indebtedness outstanding at such time or otherwise affect our capital structure or credit ratings.

COO will not be required to make a Change of Control Offer upon a Change of Control if a third party makes the Change of Control Offer in the manner, at the times and otherwise in compliance with the requirements set forth in the Indenture applicable to a Change of Control Offer made by COO and purchases all Notes validly tendered and not withdrawn under the Change of Control Offer.

A Change of Control Offer may be made in advance of a Change of Control, and conditioned upon the occurrence of the Change of Control, if a definitive agreement is in place for the Change of Control at the time of making the Change of Control Offer.

The definition of Change of Control includes a phrase relating to the direct or indirect sale, lease, transfer, conveyance or other disposition of “all or substantially all” of the properties or assets of COO and its Restricted Subsidiaries taken as a whole. Although there is a limited body of case law interpreting the phrase “substantially all,” there is no precise established definition of the phrase under applicable law. Accordingly, the ability of a Holder of Notes to require COO to repurchase its Notes as a result of a sale, lease, transfer, conveyance or other disposition of less than all of the properties or assets of COO and its Restricted Subsidiaries taken as a whole to another Person or group may be uncertain.

COO will comply with the requirements of Rule 14e-1 under the Exchange Act and any other securities laws and regulations thereunder to the extent those laws and regulations are applicable in connection with the repurchase of the Notes as a result of a Change of Control. To the extent that the provisions of any securities laws or regulations conflict with the Change of Control provisions of the Indenture, COO will comply with the applicable securities laws and regulations and will not be deemed to have breached its obligations under the Change of Control provisions of the Indenture by virtue of such conflict.

COO will not, and will not permit any of its Restricted Subsidiaries to, consummate an Asset Sale unless:

(1) COO (or a Restricted Subsidiary, as the case may be) receives consideration at the time of the Asset Sale at least equal to the fair market value of the assets or Equity Interests issued or sold or otherwise disposed of; and

(2) at least 75% of the aggregate consideration received by COO or such Restricted Subsidiary in the Asset Sale is in the form of cash or Cash Equivalents or any combination thereof. For purposes of this provision, each of the following will be deemed to be cash:

(a) any liabilities (as shown on COO’s or such Restricted Subsidiary’s most recent balance sheet) of COO or any Restricted Subsidiary (other than contingent liabilities, liabilities that are by their terms subordinated to the Notes or any Subsidiary Guarantee and liabilities owed to COO or any Subsidiary) that are expressly assumed by the transferee of any such assets pursuant to a customary written novation agreement that releases COO or such Restricted Subsidiary from further liability;

(b) any non-cash consideration received by COO or such Restricted Subsidiary from such transferee that are converted by COO or such Restricted Subsidiary into cash or Cash Equivalents within 180 days following the closing of such Asset Sale, to the extent of the cash or Cash Equivalents received in that conversion;

(c) the fair market value of (i) any assets (other than securities) used or useful in a Permitted Business, (ii) Equity Interests acquired from a Person other than COO or any Restricted Subsidiary in a Person that is a Restricted Subsidiary or a Person engaged in a Permitted Business that shall become a Restricted Subsidiary immediately upon the acquisition of such Person by COO or (iii) a combination of (i) and (ii); and

(d) any Designated Non-cash Consideration received by COO or any of its Restricted Subsidiaries in such Asset Sale having an aggregate fair market value, taken together with all other Designated Non-cash Consideration received pursuant to this clause (d) that has not, prior to such time, been converted into cash or Cash Equivalents, not to exceed the greater of (i) $25.0 million or (ii) 2.0% of COO’s Consolidated Tangible Assets at the time of receipt of such Designated Non-cash Consideration, with the fair market value of each item of Designated Non-cash Consideration being measured at the time received and without giving effect to subsequent changes in value.

Within 365 days after the receipt of any Net Proceeds from an Asset Sale, COO or the Restricted Subsidiary, as the case may be, may apply such Net Proceeds at its option:

(1) to prepay, repay, purchase, repurchase or redeem any Senior Indebtedness of COO or any Restricted Subsidiary of COO (other than Indebtedness owed to COO or an Affiliate of COO);

(2) to acquire a controlling interest in another business or all or substantially all of the assets or operating line of another business, in each case, engaged in a Permitted Business;

(4) to acquire other non-current assets (other than securities) to be used in a Permitted Business;

provided that COO or the applicable Restricted Subsidiary will be deemed to have complied with this paragraph if, within 365 days of such Asset Sale, COO or such Restricted Subsidiary shall have commenced and not completed or abandoned an expenditure or Investment, or entered into a binding agreement with respect to an expenditure or Investment, in compliance with this paragraph, and that expenditure or Investment is substantially completed within a date one year and six months after the date of such Asset Sale. Pending the final application of any such Net Proceeds, COO may expend or invest such Net Proceeds in any manner that is not prohibited by the Indenture. Any Net Proceeds from Asset Sales described in this paragraph that are not applied or invested as provided in the first sentence of this paragraph shall be deemed to constitute “Excess Asset Sale Proceeds.”

When the aggregate amount of Excess Asset Sale Proceeds exceeds $50.0 million, COO will, within 60 days after the designation of such proceeds as Excess Asset Sale Proceeds, make an offer to the Holders of Notes and, to the extent required, the

holders of any other Senior Indebtedness that is subject to requirements with respect to the application of net proceeds from asset sales that are substantially similar to those contained in this covenant (an “Asset Sale Offer”) to purchase on a pro rata basis the maximum principal amount of the Notes and such other Senior Indebtedness that may be purchased or prepaid, as applicable, out of the Excess Asset Sale Proceeds, at an offer price in cash in an amount equal to 100% of the principal amount thereof (or accreted amount in the case of any Senior Indebtedness issued with original issue discount) plus accrued and unpaid interest thereon to the date of purchase.

To the extent that the aggregate principal amount of Notes and other Senior Indebtedness tendered (and electing to be redeemed or repaid, as applicable) pursuant to an Asset Sale Offer is less than the Excess Asset Sale Proceeds, COO and its Restricted Subsidiaries may use any remaining Excess Asset Sale Proceeds for general corporate purposes and any other purpose not prohibited by the Indenture. If the aggregate principal amount of the Notes and such other Senior Indebtedness surrendered by holders thereof exceeds the amount of the Excess Asset Sale Proceeds, COO will select the Notes and such other Senior Indebtedness to be purchased on a pro rata basis based on the principal amount of Notes and such other Senior Indebtedness tendered in the offering. Upon completion of each Asset Sale Offer, the amount of Excess Asset Sale Proceeds will be reset at zero.

COO will comply with the requirements of Rule 14e-1 under the Exchange Act and any other securities laws and regulations thereunder to the extent those laws and regulations are applicable in connection with each repurchase of Notes pursuant to an Asset Sale Offer. To the extent that the provisions of any securities laws or regulations conflict with the Asset Sale provisions of the Indenture, COO will comply with the applicable securities laws and regulations and will not be deemed to have breached its obligations under the Asset Sale provisions of the Indenture by virtue of such conflict.

COO will not, and will not permit any of its Restricted Subsidiaries to, directly or indirectly:

(1) declare or pay any dividend or make any other payment or distribution on account of COO’s or any of its Restricted Subsidiaries’ Equity Interests (including, without limitation, any payment in connection with any merger or consolidation involving COO or any of its Restricted Subsidiaries) or to the direct or indirect holders of COO’s or any of its Restricted Subsidiaries’ Equity Interests in their capacity as such (other than dividends or distributions payable in Equity Interests (other than Disqualified Stock) of COO or payable to COO or a Restricted Subsidiary of COO);

(2) purchase, redeem or otherwise acquire or retire for value (including, without limitation, in connection with any merger or consolidation involving COO) any Equity Interests of COO or any direct or indirect parent of COO (except in exchange for Equity Interests (other than Disqualified Stock) of COO);

(3) make any payment on or with respect to, or purchase, redeem, defease or otherwise acquire or retire for value any Subordinated Indebtedness (other than intercompany Indebtedness between COO and a Restricted Subsidiary or between Restricted Subsidiaries of COO), except a payment of interest or principal at the Stated Maturity thereof or within one year of the Stated Maturity thereof; or

(all such payments and other actions set forth in clauses (1) through (4) above being collectively referred to as “Restricted Payments”) unless, at the time of and after giving effect to such Restricted Payment:

(1) no Default or Event of Default has occurred and is continuing or would occur as a consequence of such Restricted Payment;

(2) COO could incur at least $1.00 of additional Indebtedness pursuant to the Fixed Charge Coverage Ratio test set forth under “—Incurrence of Indebtedness and Issuance of Preferred Stock;” and

(3) such Restricted Payment, together with the aggregate amount of all other Restricted Payments made by COO or any of its Restricted Subsidiaries (excluding Restricted Payments permitted by clauses (1), (3), (4), (5), (7), (8), (9), (10), (11) and (12) of the following paragraph) after the date of the Indenture is less than the sum (the “Restricted Payments Basket”), without duplication, of:

(a) 50% of the Consolidated Net Income of COO on a cumulative basis during the period (taken as one accounting period) beginning on the first day of the fiscal quarter in which the Notes are first issued and ending on the last day of COO’s last fiscal quarter ending prior to the date of such proposed Restricted Payment for which internal financial statements are available (or, if such Consolidated Net Income for such period is a deficit, less 100% of such deficit), plus

(b) 100% of the aggregate net cash proceeds received by COO (including the fair market value of any Permitted Business or long-term assets that are used or useful in a Permitted Business to the extent acquired in consideration of Equity Interests of COO (other than Disqualified Stock)) since the date of the Indenture as a contribution to its common equity capital or from the issue or sale of Equity Interests of COO (other than Disqualified Stock) or from the issue or sale of convertible or exchangeable Disqualified Stock or convertible or exchangeable debt securities of COO that have been converted into or exchanged for Equity Interests (other than Disqualified Stock) of COO (other than (i) Equity Interests (or Disqualified Stock or debt securities) sold to a Restricted Subsidiary of COO or (ii) net cash proceeds received by COO from Equity Offerings to the extent applied to redeem the Notes in accordance with the third paragraph set forth under “—Optional Redemption” above), plus

(c) to the extent that any Restricted Investment that was made after the date of the Indenture is sold for cash or otherwise liquidated or repaid for cash, an amount (to the extent not otherwise included in the computation of the Restricted Payments Basket) equal to the lesser of (i) the cash return of capital with respect to such Restricted Investment and (ii) the initial amount of such Restricted Investment, in either case, less the cost of the disposition of such Investment and net of taxes, plus

(d) to the extent that any Unrestricted Subsidiary designated as such after the date of the Indenture is redesignated a Restricted Subsidiary, an amount (to the extent not otherwise included in the calculation of the Restricted Payments Basket) equal to the lesser of (i) the aggregate amount of COO’s Restricted Investment in such Subsidiary to the extent not previously repaid or otherwise reduced and (ii) the fair market value of COO’s Restricted Investment in the Unrestricted Subsidiary at the time of the redesignation.

(1) the payment of a dividend or distribution to Chesapeake Energy Corporation, or a Subsidiary thereof, in an amount not to exceed the net proceeds from the issuance and sale of the Notes on the Initial Issuance Date, provided that $100 million of such net proceeds shall not be a permitted payment pursuant to this provision unless COO has closed a Qualifying Credit Facility;

(2) the payment of any dividend or distribution within 60 days after the date of its declaration, if at the date of declaration the payment would have complied with the provisions of the Indenture;

(3) the redemption, repurchase, retirement, defeasance or other acquisition of any (A) Subordinated Indebtedness of COO or any Subsidiary Guarantor or (B) Equity Interests of COO in exchange for, or out of the net cash proceeds of, the substantially concurrent contribution (other than from a Restricted Subsidiary of COO) to the equity capital of COO or sale (other than to a Restricted Subsidiary of COO) of COO’s Equity Interests (other than Disqualified Stock), with a sale being deemed substantially concurrent if such redemption, repurchase, retirement, defeasance or acquisition occurs not more than 60 days after such sale; provided, however, that the amount of any such net cash proceeds that are utilized for any such redemption, repurchase, retirement, defeasance or other acquisition will be excluded from the calculation of the Restricted Payments Basket;

(4) the defeasance, redemption, repurchase, retirement or other acquisition of Subordinated Indebtedness of COO or any Subsidiary Guarantor, with the net cash proceeds from an incurrence of, or in exchange for, Permitted Refinancing Indebtedness;

(5) the declaration or payment of any dividend or distribution by a Restricted Subsidiary of COO to the holders of its Equity Interests on a pro rata basis;

(6) the repurchase, redemption or other acquisition or retirement for value of any Equity Interests of COO pursuant to any director or employee equity subscription agreement or equity option agreement or other employee benefit plan or to satisfy obligations under any Equity Interests appreciation rights or option plan or similar arrangement; provided that the aggregate price paid for all such repurchased, redeemed, acquired or retired Equity Interests may not exceed $5.0 million in any calendar year;

(7) the purchase, repurchase, redemption or other acquisition or retirement for value of Equity Interests deemed to occur upon the exercise of options, warrants, incentives, rights to acquire Equity Interests or other convertible securities if such Equity Interests represent a portion of the exercise or exchange price thereof, and any purchase, repurchase, redemption or other acquisition or retirement for value of Equity Interests made in lieu of withholding taxes in connection with any exercise or exchange of options, warrants, incentives or rights to acquire Equity Interests;

(8) any purchase, repurchase, redemption, retirement, defeasance or other acquisition for value of any Subordinated Indebtedness pursuant to the provisions of such Subordinated Indebtedness upon a Change of Control, at a purchase price not greater than 101% of the principal amount of such Subordinated Indebtedness, or an Asset Sale, at a purchase price not greater than 100% of the principal amount of such Subordinated Indebtedness, after COO shall have complied with the provisions set forth under “—Repurchase at the Option of Holders—Asset Sales” or “—Repurchase at the Option of Holders—Change of Control” above, as the case may be, and repurchased all Notes validly tendered for payment in connection with the Change of Control Offer or Asset Sale Offer, as the case may be;

(9) the purchase by COO of fractional shares arising out of stock dividends, splits or combinations or business combinations;

(10) the acquisition in open-market purchases of COO’s Equity Interests for matching contributions to COO’s employee retirement, stock purchase and deferred compensation plans in the ordinary course of business;

(11) the declaration and payment of dividends on Preferred Stock of COO (other than Disqualified Stock) issued after the Initial Issuance Date in an aggregate amount not to exceed the amount of Designated Proceeds, provided that such Designated Proceeds are not included in the calculation of the Restricted Payments Basket; or

(12) dividends, payments and other distributions pursuant to a tax sharing agreement or other similar arrangement to any equity owner of COO or to any Person with whom COO and its Restricted Subsidiaries file a consolidated, combined or similar tax return or with which COO and its Restricted Subsidiaries are part of a consolidated, combined or similar group for tax purposes, provided that such dividends, payments and distributions do not exceed the amount of taxes COO and its Restricted Subsidiaries collectively would have to pay on a stand-alone basis as a separate corporate taxable entity; or

(13) other Restricted Payments in an aggregate amount since the Initial Issuance Date not to exceed the greater of (a) $100.0 million and (b) 5.0% of Consolidated Tangible Assets determined at the time of making any such Restricted Payment;

provided that with respect to subsections (4), (5), (6), (7), (8), (10), (11) and (13) of this paragraph, no Default or Event of Default shall have occurred and be continuing after such transaction.

The amount of all Restricted Payments (other than cash) will be the fair market value on the date of the Restricted Payment of the asset(s) or securities proposed to be transferred or issued by COO or such Restricted Subsidiary, as the case may be, pursuant to the Restricted Payment. For purposes of determining compliance with this “Restricted Payments” covenant, if a Restricted Payment meets the criteria of more than one of the categories of Restricted Payments described in the preceding clauses (1) through (13) or is permitted to be made pursuant to the first paragraph of this covenant, COO will be permitted to classify (or later classify or reclassify in whole or in part in its sole discretion) such Restricted Payment in any manner that complies with this covenant.

COO will not, and will not permit any of its Restricted Subsidiaries to, directly or indirectly, create, incur, issue, assume, guarantee or otherwise become directly or indirectly liable, contingently or otherwise, with respect to (collectively, “incur”) any Indebtedness (including Acquired Debt), other than Permitted Indebtedness, COO will not, and will not permit any of its Restricted Subsidiaries to, issue any Disqualified Stock, and COO will not permit any Restricted Subsidiary that is not a Subsidiary Guarantor to issue any Preferred Stock unless the Fixed Charge Coverage Ratio for COO’s most recently ended four full fiscal quarters (or such shorter period as permitted under the definition of “Fixed Charge Coverage Ratio”) for which internal financial statements are available immediately preceding the date on which such additional Indebtedness is incurred or such Disqualified Stock or Preferred Stock is issued would have been at least 2.0 to 1.0, determined on a pro forma basis (including a pro forma application of the net proceeds therefrom), as if the additional Indebtedness had been incurred or Disqualified Stock or Preferred Stock had been issued, as the case may be, at the beginning of such reference period.

The first paragraph of this covenant will not prohibit the incurrence of any of the following items of Indebtedness (collectively, “Permitted Indebtedness”) or the issuance of any Preferred Stock described in clause (12) below:

(1) the incurrence by COO or any of its Restricted Subsidiaries of Indebtedness under one or more Credit Facilities in an aggregate principal amount (or accreted value, as applicable) at any one time outstanding under this clause (1) not to exceed the greater of (a) $750.0 million or (b) the sum of $350 million plus 25% of COO’s Consolidated Tangible Assets at the time of incurrence;

(2) the incurrence by COO or its Restricted Subsidiaries of the Existing Indebtedness;

(3) the incurrence by COO and the Subsidiary Guarantors of Indebtedness represented by the Notes issued and sold, and the related Subsidiary Guarantees issued, on the date of the Indenture and the exchange notes and the related Subsidiary Guarantees issued pursuant to any registration rights agreement;

(4) the incurrence by COO or any of its Restricted Subsidiaries of Indebtedness represented by Capital Lease Obligations, mortgage financings or purchase money obligations, in each case, incurred for the purpose of financing all or any part of the purchase price or cost of construction or improvement of property, plant or equipment used in the business of COO or such Restricted Subsidiary or Attributable Debt in respect of sale-leaseback transactions, provided that the aggregate principal amount of Indebtedness incurred pursuant to this clause (4), including all Permitted Refinancing Indebtedness incurred to extend, refinance, renew, replace, defease or refund such Indebtedness, shall not exceed at any time outstanding, the greater of (a) $75.0 million or (b) 5.0% of COO’s Consolidated Tangible Assets at the time of incurrence;

(5) the incurrence by COO or any of its Restricted Subsidiaries of Permitted Refinancing Indebtedness in exchange for, or the net proceeds of which are used to extend, refinance, renew, replace, defease or refund Indebtedness that was permitted by the Indenture to be incurred under the first paragraph of this covenant or clauses (2), (3), (9) or (13) of this paragraph or this clause (5);

(6) the incurrence by COO or any of its Restricted Subsidiaries of intercompany Indebtedness between or among COO and any of its Restricted Subsidiaries; provided, however, that:

(a) if COO is the obligor on such Indebtedness and a Subsidiary Guarantor is not the obligee, such Indebtedness must be expressly subordinated to the prior payment in full in cash of all Obligations with respect to the Notes, or if a Subsidiary Guarantor is the obligor on such Indebtedness and neither COO nor another Subsidiary Guarantor is the obligee, such Indebtedness must be expressly subordinated to the prior payment in full in cash of all Obligations with respect to the Subsidiary Guarantee of such Subsidiary Guarantor; and

(b)(i) any subsequent issuance or transfer of Equity Interests that results in any such Indebtedness being held by a Person other than COO or a Restricted Subsidiary of COO and (ii) any sale or other transfer of any such Indebtedness to a Person that is neither COO nor a Restricted Subsidiary of COO will be deemed, in each case, to constitute an incurrence of such Indebtedness by COO or such Restricted Subsidiary, as the case may be, that was not permitted by this clause (6);

(7) the incurrence by COO or any of its Restricted Subsidiaries of Hedging Obligations in the ordinary course of business for bona fide hedging purposes and not for speculative purposes;

(8) the incurrence by COO or any of its Restricted Subsidiaries of Indebtedness arising from agreements of COO or any of its Restricted Subsidiaries providing for indemnification, adjustment of purchase price, earn-outs or similar obligations, in each case, incurred in connection with the disposition or acquisition of any business, assets or a Restricted Subsidiary of COO or any business or assets of its Restricted Subsidiaries, other than guarantees of Indebtedness incurred by any Person acquiring all or any portion of such business, assets or a Restricted Subsidiary of COO or any of its Restricted Subsidiaries for the purposes of financing such acquisition; provided, however, that:

(a) such Indebtedness is not reflected on the balance sheet of COO or any of its Restricted Subsidiaries (contingent obligations referred to in a footnote to financial statements and not otherwise reflected on the balance sheet will not be deemed to be reflected on such balance sheet for purposes of this clause (a)); and

(b) the maximum liability in respect of all such Indebtedness incurred in connection with a disposition shall at no time exceed the gross proceeds including noncash proceeds (the fair market value of such noncash proceeds being measured at the time received and without giving effect to any subsequent changes in value) actually received by COO and its Restricted Subsidiaries in connection with such disposition;

(9) the incurrence by COO or any of its Restricted Subsidiaries of Permitted Acquisition Indebtedness;

(10) the guarantee by COO or any Subsidiary Guarantor of Indebtedness of COO or any of COO’s Restricted Subsidiaries that was permitted to be incurred by another provision of this covenant; provided that if the Indebtedness being guaranteed is Subordinated Indebtedness, then the related guarantee shall be subordinated in right of payment to the Notes and the Subsidiary Guarantees, as the case may be;

(11) the incurrence by COO or any of its Restricted Subsidiaries of Indebtedness in respect of bid, performance, surety and similar bonds issued for the account of COO or any of its Restricted Subsidiaries in the ordinary course of business, including guarantees and obligations of COO or any of its Restricted Subsidiaries with respect to letters of credit supporting such obligations (in each case other than an obligation for money borrowed);

(12) the issuance by any of COO’s Restricted Subsidiaries to COO or to any of its Restricted Subsidiaries of any Preferred Stock; provided, however, that:

(a) any subsequent issuance or transfer of Equity Interests that results in any such Preferred Stock being held by a Person other than COO or a Restricted Subsidiary of COO; and

(b) any sale or other transfer of any such Preferred Stock to a Person that is not either COO or a Restricted Subsidiary of COO

shall be deemed, in each case, to constitute an issuance of such Preferred Stock by such Restricted Subsidiary that was not permitted by this clause (12); and

(13) the incurrence by COO or any of its Restricted Subsidiaries of additional Indebtedness in an aggregate principal amount (or accreted value, as applicable) then outstanding, not to exceed the greater of (a) $75.0 million or (b) 5.0% of COO’s Consolidated Tangible Assets determined at the time of incurrence.

For purposes of determining compliance with this “Incurrence of Indebtedness and Issuance of Preferred Stock” covenant, if an item of Indebtedness (including Acquired Debt) meets the criteria of more than one of the categories of Permitted Indebtedness described in clauses (1) through (13) above, or is entitled to be incurred pursuant to the first paragraph of this covenant, COO will be permitted to classify (or later classify or reclassify in whole or in part in its sole discretion) such item of Indebtedness in any manner that complies with this covenant. Any Indebtedness under Credit Facilities on the date of the Indenture shall be considered incurred under clause (1) of the second paragraph of this covenant.

The accrual of interest, the accretion or amortization of original issue discount, the payment of interest on any Indebtedness in the form of additional Indebtedness with the same terms, and the payment of dividends on Disqualified Stock or Preferred Stock in the form of additional shares of the same class of Disqualified Stock or Preferred Stock will not be deemed to be an incurrence of Indebtedness or an issuance of Disqualified Stock or Preferred Stock, as the case may be, for purposes of this covenant; provided, in each such case, that the amount thereof is included in Fixed Charges of COO as accrued. Notwithstanding any other provision of this covenant, the maximum amount of Indebtedness that COO or any Restricted Subsidiary may incur pursuant to this covenant will not be deemed to be exceeded solely as a result of fluctuations in exchange rates or currency values. Further, the accounting reclassification of any obligation of COO or any of its Restricted Subsidiaries as Indebtedness will not be deemed an incurrence of Indebtedness for purposes of this covenant.

COO will not, and will not permit any Restricted Subsidiary to, create, incur, assume or otherwise cause or suffer to exist or become effective any Lien (other than Permitted Liens) securing Indebtedness upon any of their property or assets, now owned or hereafter acquired, unless:

(1) in the case of Liens securing Subordinated Obligations of COO or a Restricted Subsidiary, the Notes or Subsidiary Guarantees, as applicable, are contemporaneously secured by a Lien on such property or assets on a senior basis to the Subordinated Obligations so secured with the same priority that the Notes or Subsidiary Guarantees, as applicable, have to such Subordinated Obligations until such time as such Subordinated Obligations are no longer so secured by a Lien; and

(2) in the case of Liens securing Senior Indebtedness of COO or a Restricted Subsidiary, the Notes or Subsidiary Guarantees, as applicable, are contemporaneously secured by a Lien on such property or assets on an equal and ratable basis with the Senior Indebtedness so secured until such time as such Senior Indebtedness is no longer so secured by a Lien.

COO will not, and will not permit any of its Restricted Subsidiaries to, directly or indirectly, create or otherwise cause or permit to exist or become effective any consensual encumbrance or restriction on the ability of any Restricted Subsidiary to:

(1) pay dividends or make any other distributions on its Capital Stock to COO or any of its Restricted Subsidiaries; provided that the priority of any Preferred Stock in receiving dividends or liquidating distributions prior to the payment of dividends or liquidating distributions on Capital Stock shall not be a restriction on the ability to make distributions on Capital Stock;

(2) make loans or advances or pay any Indebtedness or other Obligations owed to COO or any of its Restricted Subsidiaries; or

(3) transfer any of its properties or assets to COO or any of its Restricted Subsidiaries.

The preceding restrictions will not apply to encumbrances or restrictions existing under or by reason of:

(1) agreements as in effect on the date of the Indenture and any amendments, modifications, restatements, renewals, increases, supplements, refundings, replacements or refinancings of those agreements or the Indebtedness to which they relate, provided that the amendments, modifications, restatements, renewals, increases, supplements, refundings, replacements or refinancings are no more restrictive, taken as a whole, with respect to such dividend, distribution and other payment restrictions than those contained in those agreements on the date of the Indenture;

(4) any instrument governing Indebtedness or Capital Stock of a Person acquired by COO or any of its Restricted Subsidiaries as in effect at the time of such acquisition (but not created in contemplation thereof), which encumbrance or restriction is not applicable to any Person, or the properties or assets of any Person, other than the Person, or the property or assets of the Person, so acquired, provided that, in the case of Indebtedness, such Indebtedness was otherwise permitted by the terms of the Indenture to be incurred;

(5) Capital Lease Obligations, sale and leaseback transactions, mortgage financings or purchase money obligations, in each case for property acquired in the ordinary course of business that impose restrictions on that property of the nature described in clause (3) of the preceding paragraph;

(6) restrictions imposed under any agreement to sell Equity Interests or assets, as permitted under the Indenture, to any Person that impose restrictions on that property of the nature described in clause (3) of the preceding paragraph pending the closing of such sale;

(7) any agreement for the sale or other disposition of a Restricted Subsidiary of COO that restricts distributions by that Restricted Subsidiary pending its sale or other disposition;

(8) Permitted Refinancing Indebtedness, provided that the restrictions contained in the agreements governing such Permitted Refinancing Indebtedness are no more restrictive, taken as a whole, than those contained in the agreements governing the Indebtedness being refinanced;

(9) Liens securing Indebtedness otherwise permitted to be incurred under the provisions of the covenant described above under “—Liens” that limit the right of the debtor to dispose of the assets subject to such Liens;

(10) customary provisions in joint venture agreements, partnership agreements, limited liability company organizational documents, shareholder agreements and other similar agreements entered into in the ordinary course of business that restrict the disposition or distribution of ownership interests in or assets of such joint venture, partnership, limited liability company, corporation or similar Person;

(11) any agreement or instrument relating to any property or assets acquired after the date of the Indenture, so long as such encumbrance or restriction relates only to the property or assets so acquired and is not and was not created in anticipation of such acquisitions;

(12) restrictions on cash or other deposits or net worth imposed by customers under contracts entered into in the ordinary course of business;

(13) encumbrances or restrictions contained in, or in respect of, Hedging Obligations permitted under the Indenture from time to time;

(14) with respect to any Foreign Subsidiary, any encumbrance or restriction contained in the terms of any Indebtedness or any agreement pursuant to which such Indebtedness was incurred if either (a) the encumbrance or restriction applies only in the event of a payment default or a default with respect to a financial covenant in such Indebtedness or agreement or (b) COO determines in good faith that any such encumbrance or restriction will not materially affect COO’s ability to make principal or interest payments on the Notes; and

(15) any other agreement governing Indebtedness of COO or any Restricted Subsidiary that is permitted to be incurred by the covenant described under “—Incurrence of Indebtedness and Issuance of Preferred Stock,” including but not limited to any Credit Facility; provided, however, that such encumbrances or restrictions are not materially more restrictive, taken as a whole, than those contained in the Indenture as in effect on the date of the Indenture or in the Credit Agreement as in effect on the original date of the Credit Agreement.

COO may not, directly or indirectly: (1) consolidate or merge with or into another Person (whether or not COO is the survivor); or (2) sell, assign, transfer, lease, convey or otherwise dispose of all or substantially all of the properties and assets of COO and its Restricted Subsidiaries (taken as a whole) in one or more related transactions, to another Person; unless:

(1) either: (a) COO is the survivor; or (b) the Person formed by or surviving any such consolidation or merger (if other than COO) or to which such sale, assignment, transfer, lease, conveyance or other disposition has been made (the “Successor”) is a Person organized or existing under the laws of the United States, any state of the United States or the District of Columbia; provided, that if the Successor is not a corporation, a Restricted Subsidiary that is a corporation expressly assumes as co-obligor all of the obligations of COO under the Indenture and the Notes pursuant to a supplemental indenture to the Indenture executed and delivered to the trustee;

(2) the Successor assumes all the obligations of COO under the Notes, the Indenture and the registration rights agreement pursuant to agreements reasonably satisfactory to the trustee;

(4) immediately after giving pro forma effect to such transaction and the assumption of the obligations as set forth in clause (2) above and the incurrence of any Indebtedness to be incurred in connection therewith, and the use of any net proceeds therefrom on a pro forma basis, (i) COO or its Successor, as the case may be, could incur $1.00 of additional Indebtedness pursuant to the Fixed Charge Coverage Ratio in the first paragraph of the “Incurrence of Indebtedness and Issuance of Preferred Stock” covenant or (ii) the Fixed Charge Coverage Ratio for COO or its Successor, as the case may be, would be greater than or equal to such Fixed Charge Coverage Ratio prior to such transaction;

(5) each Subsidiary Guarantor, unless such Subsidiary Guarantor is the Person with which COO has entered into a transaction under this covenant, will have confirmed to the trustee in writing that its Subsidiary Guarantee will apply to the obligations of COO or the Successor, as the case may be, in accordance with the Notes, the Indenture and the registration rights agreement; and

(6) COO has delivered to the trustee an officers’ certificate and an opinion of counsel, each stating that such consolidation, merger or disposition and such supplemental indenture (if any) comply with the Indenture;

provided, however, that clause (4) above will not apply (i) if, in the good faith determination of the Board of COO, whose determination shall be evidenced by a Board Resolution, the principal purpose of such transaction is to change the state of incorporation of COO, the organizational form of COO or both (provided that at all times there shall be at least one co-Issuer of the Notes that is a corporation), and any such transaction shall not have as one of its purposes the evasion of the foregoing limitations; or (ii) to any consolidation, merger, sale, assignment, transfer, conveyance or other disposition of assets between or among COO and any of its Restricted Subsidiaries.

A Subsidiary Guarantor may not sell or otherwise dispose of all or substantially all of its properties or assets to, or consolidate with or merge with or into (whether or not such Subsidiary Guarantor is the surviving Person), another Person, other than COO or another Subsidiary Guarantor, unless:

(1) immediately after giving effect to such transaction, no Default or Event of Default exists; and

(a) the Person acquiring the properties or assets in any such sale or other disposition or the Person formed by or surviving any such consolidation or merger (if other than the Subsidiary Guarantor) unconditionally assumes all the obligations of that Subsidiary Guarantor under the Notes, the Indenture and its Subsidiary Guarantee on terms set forth in the Indenture; or

(b) such sale or other disposition is made in compliance with the “Asset Sale” provisions of the Indenture.

Upon any consolidation or merger of COO or a Subsidiary Guarantor in circumstances in which such Subsidiary Guarantor’s Subsidiary Guarantee is not being released, or any transfer of all or substantially all of the assets of COO or a Subsidiary Guarantor in accordance with the foregoing in circumstances in which such Subsidiary Guarantor’s Subsidiary Guarantee is not being released, in which COO or such Subsidiary Guarantor is not the continuing obligor under the Notes or its Subsidiary Guarantee, as applicable, the surviving entity formed by such consolidation or into which COO or such Subsidiary Guarantor is merged or the Person to which the sale, conveyance, lease, transfer, disposition or assignment is made will succeed to, and be substituted for, and may exercise every right and power of, COO or such Subsidiary Guarantor under the Indenture, the Notes and the Subsidiary Guarantees with the same effect as if such surviving entity had been named therein as COO or such Subsidiary Guarantor and, except in the case of a lease, COO or such Subsidiary Guarantor, as the case may be, will be released from the obligation to pay the principal of and interest on the Notes or in respect of its Subsidiary Guarantee, as the case may be, and all of COO’s or such Subsidiary Guarantor’s other obligations and covenants under the Notes, the Indenture and its Subsidiary Guarantee, if applicable.

Although there is a limited body of case law interpreting the phrase “substantially all,” there is no precise established definition of the phrase under applicable law. Accordingly, in certain circumstances there may be a degree of uncertainty as to whether a particular transaction would involve “all or substantially all” of the properties or assets of a Person.

COO will not, and will not permit any of its Restricted Subsidiaries to, directly or indirectly, in one transaction or a series of related transactions, sell, lease, transfer or otherwise dispose of any of its properties or assets to, or purchase any property or assets from, or enter into or make, amend, renew or extend any transaction, contract, agreement, understanding, loan, advance or guarantee with, or for the benefit of, any Affiliate (each, an “Affiliate Transaction”) if such Affiliate Transaction involves aggregate consideration in excess of $1.0 million, unless:

(1) the Affiliate Transaction is on terms that, taken as a whole, are no less favorable to COO or the relevant Restricted Subsidiary than those that could reasonably be expected to have been obtained in a comparable transaction by COO or such Restricted Subsidiary with a Person who is not an Affiliate of COO or any Restricted Subsidiary or is otherwise fair to COO and its Restricted Subsidiaries from a financial point of view; and

(a) with respect to any Affiliate Transaction or series of Affiliate Transactions involving aggregate consideration in excess of $30.0 million, an officers’ certificate certifying that such Affiliate Transaction or series of Affiliate Transactions complies with the preceding clause (1) of this covenant; and

(b) with respect to any Affiliate Transaction or series of related Affiliate Transactions involving aggregate consideration in excess of $60.0 million, a Board Resolution of COO set forth in an officers’ certificate certifying that such Affiliate Transaction complies with the preceding clause (1) of this covenant and has been approved by the Board.

The following items will not be deemed to be Affiliate Transactions and, therefore, will not be subject to the provisions of the prior paragraph:

(1) any employment agreement or arrangement, equity award, equity option or equity appreciation agreement, plan agreement or similar compensation arrangement, employee benefit plan, officer or director indemnification agreement or any similar arrangement entered into by COO or any of its Restricted Subsidiaries in the ordinary course of business and any payments or awards pursuant thereto;

(2) transactions between or among (a) COO and one or more of its Restricted Subsidiaries and (b) any Restricted Subsidiaries;

(3) transactions with a Person that is an Affiliate of COO solely because COO or any of its Restricted Subsidiaries owns an Equity Interest in or otherwise controls such Person;

(4) transactions pursuant to the administrative services agreement, the real property lease agreements and other arrangements with respect to accounting, treasury, information technology, insurance and other corporate services, general overhead and other administrative matters and expense reimbursements and any other agreements or arrangements in effect on the date of the Indenture, or any amendment, modification, or supplement thereto or replacement thereof, as long as such agreement or arrangement, as so amended, modified, supplemented or replaced, taken as a whole, is not materially less favorable to COO and its Restricted Subsidiaries than the agreement or arrangement in existence on the date of the Indenture;

(5) transactions with customers, clients, suppliers or purchasers or sellers of goods or services, including pursuant to the master services agreement and the services agreement in each case in the ordinary course of business and otherwise in accordance with the terms of the Indenture, on terms that are not materially less favorable to COO and its Restricted Subsidiaries than those that could reasonably be expected to have been obtained in a comparable transaction by COO or its Restricted Subsidiaries with a Person who is not an Affiliate of COO or any Restricted Subsidiary;

(6) loans or advances to officers, directors, managers and employees for moving, entertainment and travel expenses, drawing accounts and similar expenditures and other purposes, in each case, in the ordinary course of business;

(7) maintenance in the ordinary course of business of customary benefit programs or arrangements for employees, officers, directors or managers, including vacation plans, health and life insurance plans, deferred compensation plans and retirement or savings plans and similar plans;

(8) fees and compensation paid to, and indemnity provided on behalf of, officers, directors, managers, employees or consultants of COO or any of its Restricted Subsidiaries in their capacity as such, to the extent such fees and compensation are reasonable and customary;

(9) sales of Equity Interests of COO (other than Disqualified Stock) to Affiliates of COO or any of its Restricted Subsidiaries; and

(10) Restricted Payments that are permitted by the covenant described under “—Restricted Payments.”

The Board of COO may designate any Restricted Subsidiary of COO to be an Unrestricted Subsidiary if that designation would not cause a Default. If a Restricted Subsidiary of COO is designated as an Unrestricted Subsidiary, the aggregate fair market value of all outstanding Investments owned by COO and its Restricted Subsidiaries in the Subsidiary properly designated will be deemed to be an Investment made as of the time of the designation and will reduce the amount available for Restricted Payments under the first paragraph of the covenant described above under “—Restricted Payments” or represent Permitted Investments, as determined by COO. That designation will only be permitted if the Investment would be permitted at that time and if the Subsidiary so designated otherwise meets the definition of an Unrestricted Subsidiary.

The Board of COO may at any time designate any Unrestricted Subsidiary to be a Restricted Subsidiary if (1) all Indebtedness, Liens and Investments of such Subsidiary outstanding or in existence immediately following such designation would, if incurred or made at such time by a Restricted Subsidiary of COO, have been permitted to be incurred or made for all purposes of the Indenture and (2) no Default or Event of Default would be in existence following such designation.

If, after the date of the Indenture, any Restricted Subsidiary of COO that is not already a Subsidiary Guarantor incurs any Indebtedness or guarantees any Indebtedness of COO or any Subsidiary Guarantor and the aggregate principal amount of Indebtedness incurred or guaranteed by such Restricted Subsidiary exceeds $15.0 million, then that Subsidiary must become a Subsidiary Guarantor by executing a supplemental indenture and delivering it to the trustee within 45 days of the end of the fiscal quarter during which it guaranteed or incurred such other Indebtedness, as the case may be. The foregoing requirement does not apply to Subsidiaries of COO that have properly been designated as Unrestricted Subsidiaries in accordance with the Indenture for so long as they continue to constitute Unrestricted Subsidiaries. Any Subsidiary Guarantee of a Restricted Subsidiary that was incurred pursuant to this paragraph shall be subject to the release and other provisions of the Indenture described above under “—Subsidiary Guarantees” and below under “Legal Defeasance and Covenant Defeasance.”

The Indenture also permits COO’s parent entity to guarantee the Notes. However, such entity will not become subject to the covenants contained in the Indenture by virtue of having delivered such guarantee.

COF will not hold any material assets, become liable for any material obligations or engage in any significant business activities; provided that COF may be a co-obligor or guarantor with respect to Indebtedness if COO is an obligor on such Indebtedness and the net proceeds of such Indebtedness are received by COO, COF or one or more of their Restricted Subsidiaries. COF shall be a wholly owned subsidiary of COO at all times.

For so long as any of the Notes are outstanding and COO is not subject to the requirements of Section 13 or 15(d) of the Exchange Act, COO shall file with the trustee and post on its website, within 10 Business Days after the applicable date by which it would have been required to file the same with the Commission (as if COO were a non-accelerated filer under the Exchange Act), all annual and quarterly financial statements, including any notes thereto (and with respect to annual reports, an auditors’ report by a firm of established national reputation), and a “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” both comparable to that which COO would have been required to include in such annual and quarterly reports on Forms 10-K and 10-Q, as if COO had been subject to the requirements of Sections 13 or 15(d) of the Exchange Act. If COO becomes subject to the requirements of such Section 13 or 15(d), COO shall instead, so long as any of the Notes are outstanding, file with the Commission, within the time periods that it is required to file the same with the Commission, the annual and quarterly reports and the information, documents and other reports that COO is required to file with the Commission pursuant to such Section 13 or 15(d). Subject to the next succeeding paragraph, the financial statements, reports and other information to be provided may be provided by COO’s parent entity if such parent entity has delivered a guarantee as described above under “—Additional Guarantees.”

If (a) COO has designated any of its Subsidiaries as Unrestricted Subsidiaries or (b) COO’s parent entity is providing the required financial statements, reports and other information and such entity has material assets or operations other than COO and its Restricted Subsidiaries, then the quarterly and annual financial information required by the preceding paragraph will include a reasonably detailed presentation, either on the face of the financial statements or in the footnotes thereto, and in “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” of the financial condition and results of operations of COO and its Restricted Subsidiaries separate from the financial condition and results of operations of the Unrestricted Subsidiaries of COO or of COO’s parent entity, as applicable.

In addition, if COO is not subject to the requirements of Section 13 or 15(d) of the Exchange Act, COO will maintain a website, which may, in COO’s discretion, be non-public, to which Holders are given access and to which such information is posted.

In addition, COO and the Subsidiary Guarantors have agreed that, for so long as any Notes remain outstanding, they will furnish to the Holders and Beneficial Owners of the Notes and to securities analysts and prospective investors in the Notes, upon their request, the information required to be delivered pursuant to Rule l44A(d)(4) under the Securities Act.

If on any date following the date of the Initial Issuance Date, (i) the Notes have an Investment Grade Rating by either S&P or Moody’s and (ii) no Default has occurred and is continuing under the Indenture (the occurrence of the events described in the foregoing clauses (i) and (ii) being collectively referred to as a “Covenant Suspension Event”), then COO and its Restricted Subsidiaries will not be subject to the following covenants (collectively, the “Suspended Covenants”) during the Suspension Period:

In the event that COO and its Restricted Subsidiaries are not subject to the Suspended Covenants under the Indenture for any period of time as a result of the foregoing, and on any subsequent date (the “Reversion Date”) S&P or Moody’s, as applicable, (1) withdraws its Investment Grade Rating or downgrades the rating assigned to the Notes below an Investment Grade Rating and/or (2) COO or any of its Affiliates enters into an agreement to effect a transaction and S&P or Moody’s indicates that if consummated, such transaction (alone or together with any related recapitalization or refinancing transactions) would cause it to withdraw its Investment Grade Rating, then COO and its Restricted Subsidiaries will thereafter again be subject to the Suspended Covenants under the Indenture with respect to future events, including, without limitation, a proposed transaction described in the preceding clause (2).

The period of time between the occurrence of a Covenant Suspension Event and the Reversion Date is referred to in this description as the “Suspension Period.” Additionally, upon the occurrence of a Covenant Suspension Event, the amount of Excess Asset Sale Proceeds shall be reset at zero. In the event of any such reinstatement, no action taken or omitted to be taken by COO or any of its Restricted Subsidiaries prior to such reinstatement will give rise to a Default or Event of Default under the Indenture with respect to the Notes; provided that with respect to Restricted Payments made after any such reinstatement, the amount of Restricted Payments made will be calculated as though the covenant described under “—Certain Covenants—Restricted Payments” had been in effect prior to, and during, the Suspension Period. COO may not designate any Restricted Subsidiary as an Unrestricted Subsidiary during a Suspension Period unless such designation could otherwise be made if the Suspended Covenants were not suspended at such time and COO and its Restricted Subsidiaries were subject thereto and a Default is not occurring or would occur as a result of such designation. All Indebtedness incurred, during the Suspension Period will be classified to have been incurred or issued pursuant to clause (2) of second paragraph under “—Certain Covenants—Limitation on Indebtedness.”

If on any date following the Initial Issuance Date, (i) the Notes have an Investment Grade Rating by both S&P and Moody’s and (ii) no Default has occurred and is continuing under the Indenture, then the obligation of COO and its Restricted Subsidiaries to comply with the Suspended Covenants will be permanently terminated.

There can be no assurance that the Notes will ever achieve an Investment Grade Rating or that any such rating will be maintained.

(2) default in the payment of the principal of, or premium, if any, on the Notes when due, whether at Stated Maturity, upon redemption, repurchase, acceleration or otherwise;

(3) failure by COO or any of its Restricted Subsidiaries to comply with any of their respective agreements or covenants described above under “—Certain Covenants—Merger, Consolidation or Sale of Assets,” or failure by COO to comply with its obligation to make a Change of Control Offer as described under “—Repurchase at the Option of Holders—Change of Control” and such failure continues for 30 days after notice by the trustee or the Holders of at least 25% in principal amount of the Notes then outstanding;

(4)(a) except with respect to the covenant described under “—Certain Covenants—Reports,” failure by COO for 60 days after notice by the trustee or the Holders of at least 25% in principal amount of the Notes then outstanding of such failure to comply with any other covenant or agreement in the Indenture and (b) failure by COO for 90 days after notice of the failure has been given to COO by the trustee or by the Holders of at least 25% of the aggregate principal amount of the Notes then outstanding to comply with the covenant described under “—Certain Covenants—Reports;”

(5) default under any mortgage, indenture or instrument under which there is issued or by which there is secured or evidenced any Indebtedness for money borrowed by COO or any of its Restricted Subsidiaries (or the payment of which is guaranteed by COO or any of its Restricted Subsidiaries), whether such Indebtedness or guarantee now exists or is created after the date of the Indenture, if that default:

(a) is caused by a failure to pay principal of, or interest or premium, if any, on such Indebtedness prior to the expiration of the grace period provided in such Indebtedness (a “Payment Default”); or

(b) results in the acceleration of such Indebtedness prior to its Stated Maturity,

and, in each case, the principal amount of any such Indebtedness, together with the principal amount of any other such Indebtedness under which there has been a Payment Default or the maturity of which has been so accelerated, aggregates $50.0 million or more; provided that if any such default is cured or waived or any such acceleration rescinded, or such Indebtedness is repaid, within a period of 30 days from the continuation of such default beyond the applicable grace period or the occurrence of such acceleration, as the case may be, such Event of Default and any consequential acceleration of the Notes shall be automatically rescinded, so long as such rescission does not conflict with any judgment or decree;

(6) failure by COO or any of COO’s Restricted Subsidiaries that is a Significant Subsidiary or any group of its Restricted Subsidiaries that, taken as a whole, would constitute a Significant Subsidiary of COO to pay final judgments aggregating in excess of $50.0 million, which judgments are not paid, discharged or stayed for a period of 60 days;

(7) except as permitted by the Indenture, any Subsidiary Guarantee shall be held in any judicial proceeding to be unenforceable or invalid or shall cease for any reason to be in full force and effect or any Subsidiary Guarantor, or any Person acting on behalf of any Subsidiary Guarantor, shall deny or disaffirm its obligations under its Subsidiary Guarantee; and

(8) certain events of bankruptcy, insolvency or reorganization described in the Indenture with respect to COO or any of COO’s Restricted Subsidiaries that is a Significant Subsidiary or any group of its Restricted Subsidiaries that, taken as a whole, would constitute a Significant Subsidiary of COO.

In the case of an Event of Default arising from certain events of bankruptcy, insolvency or reorganization with respect to COO, all outstanding Notes will become due and payable immediately without further action or notice. If any other Event of Default occurs and is continuing, the trustee or the Holders of at least 25% in principal amount of the then outstanding Notes may declare all the Notes to be due and payable immediately.

Holders of the Notes may not enforce the Indenture or the Notes except as provided in the Indenture. Subject to certain limitations, Holders of a majority in principal amount of the then outstanding Notes may direct the trustee in its exercise of any trust or power. The trustee may withhold notice of any continuing Default or Event of Default from Holders of the Notes if it determines that withholding notice is in their interest, except a Default or Event of Default relating to the payment of principal of, or interest or premium, if any, on, the Notes.

The Holders of a majority in principal amount of the Notes then outstanding by notice to the trustee may on behalf of the Holders of all of the Notes waive any existing Default or Event of Default and its consequences under the Indenture except a continuing Default or Event of Default in the payment of principal of, or interest or premium, if any, on the Notes.

COO is required to deliver to the trustee annually a statement regarding compliance with the Indenture. Upon any officer of COO becoming aware of any Default or Event of Default, COO is required to deliver to the trustee a statement specifying such Default or Event of Default.

No director, officer, partner, employee, incorporator, manager or unitholder or other owner of Capital Stock of COO or any Subsidiary Guarantor, as such, will have any liability for any obligations of COO or any Subsidiary Guarantor under the Notes, the Indenture or the Subsidiary Guarantees, or for any claim based on, in respect of, or by reason of, such obligations or their creation. Each Holder of Notes, by accepting a Note, waives and releases all such liability. The waiver and release are part of the consideration for issuance of the Notes.

The Issuers may, at their option and at any time, elect to have all of their obligations discharged with respect to the outstanding Notes and all obligations of the Subsidiary Guarantors discharged with respect to their Subsidiary Guarantees (“Legal Defeasance”), except for:

(1) the rights of Holders of outstanding Notes to receive payments in respect of the principal of, and interest or premium, if any, on such Notes when such payments are due from the trust referred to below;

(2) the Issuers’ obligations with respect to the Notes concerning issuing temporary Notes, registration, transfer and exchange of Notes, mutilated, destroyed, lost or stolen Notes and the maintenance of an office or agency for payment and money for security payments held in trust;

(3) the rights, powers, trusts, duties and immunities of the trustee, and the Issuers’ obligations in connection therewith; and

In addition, the Issuers may, at their option and at any time, elect to have their obligations released with respect to certain covenants that are described in the Indenture (“Covenant Defeasance”) and thereafter any omission to comply with those covenants will not constitute a Default or Event of Default with respect to the Notes. If Covenant Defeasance occurs, certain events (not including non-payment, bankruptcy, insolvency or reorganization events) described under “—Events of Default and Remedies” will no longer constitute an Event of Default with respect to the Notes. If the Issuers exercise either their Legal Defeasance or Covenant Defeasance option, each Subsidiary Guarantor will be released and relieved of any obligations under its Subsidiary Guarantee and any security for the Notes (other than the trust) will be released.

(1) the Issuers must irrevocably deposit with the trustee, in trust, for the benefit of the Holders of the Notes, cash in U.S. dollars, non-callable Government Securities, or a combination of cash in U.S. dollars and non-callable Government Securities, in amounts as will be sufficient, in the opinion of a nationally recognized firm of independent public accountants, to pay the principal of, and interest and premium, if any, on the outstanding Notes on the date of fixed maturity or on the applicable redemption date, as the case may be, and the Issuers must specify whether the Notes are being defeased to the date of fixed maturity or to a particular redemption date;

(2) in the case of Legal Defeasance, the Issuers have delivered to the trustee an opinion of counsel reasonably acceptable to the trustee confirming that:

(a) the Issuers has received from, or there has been published by, the Internal Revenue Service a ruling; or

(b) since the date of the Indenture, there has been a change in the applicable federal income tax law,

in either case to the effect that, and based thereon such opinion of counsel will confirm that, the Holders of the outstanding Notes will not recognize income, gain or loss for federal income tax purposes as a result of such Legal Defeasance and will be subject to federal income tax on the same amounts, in the same manner and at the same times as would have been the case if such Legal Defeasance had not occurred;

(3) in the case of Covenant Defeasance, the Issuers have delivered to the trustee an opinion of counsel reasonably acceptable to the trustee confirming that the Holders of the outstanding Notes will not recognize income, gain or loss for federal income tax purposes as a result of such Covenant Defeasance and will be subject to federal income tax on the same amounts, in the same manner and at the same times as would have been the case if such Covenant Defeasance had not occurred;

(4) no Default or Event of Default has occurred and is continuing on the date of such deposit (other than a Default or Event of Default resulting from the borrowing of funds to be applied to such deposit);

(5) such Legal Defeasance or Covenant Defeasance will not result in a breach or violation of, or constitute a default under, any material agreement or instrument (other than the Indenture) to which COO or any of its Subsidiaries is a party or by which COO or any of its Subsidiaries is bound;

(6) the Issuers must deliver to the trustee an officers’ certificate stating that the deposit was not made by the Issuers with the intent of preferring the Holders of Notes over the other creditors of the Issuers with the intent of defeating, hindering, delaying or defrauding creditors of the Issuers or others; and

(7) the Issuers must deliver to the trustee an officers’ certificate and an opinion of counsel, each stating that all conditions precedent relating to the Legal Defeasance or the Covenant Defeasance have been complied with.

Except as provided in the next two succeeding paragraphs, the Indenture or the Notes may be amended or supplemented with the consent of the Holders of at least a majority in principal amount of the then outstanding Notes (including, without limitation, consents obtained in connection with a purchase of, or tender offer or exchange offer for, Notes), and any existing default or compliance with any provision of the Indenture or the Notes may be waived with the consent of the Holders of a majority in principal amount of the then outstanding Notes (including, without limitation, consents obtained in connection with a purchase of, or tender offer or exchange offer for, Notes).

Without the consent of each Holder affected, an amendment, supplement or waiver may not (with respect to any Notes held by a non-consenting Holder):

(1) reduce the principal amount of Notes whose Holders must consent to an amendment, supplement or waiver;

(2) reduce the principal of or change the fixed maturity of any Note or alter the provisions with respect to the redemption or repurchase of the Notes (other than provisions relating to the covenants described above under “—Repurchase at the Option of Holders” prior to the time COO’s obligation to offer to repurchase the Notes arises);

(4) waive a Default or Event of Default in the payment of principal of, or interest or premium, if any, on the Notes (except a rescission of acceleration of the Notes by the Holders of at least a majority in principal amount of the Notes and a waiver of the payment default that resulted from such acceleration);

(6) make any change in the provisions of the Indenture relating to waivers of past Defaults or the rights of Holders of Notes to receive payments of principal of, or interest or premium, if any, on the Notes (other than as permitted in clause (7) below);

(8) release any Subsidiary Guarantor from any of its obligations under its Subsidiary Guarantee or the Indenture, except in accordance with the terms of the Indenture; or

(9) make any change in the preceding amendment, supplement and waiver provisions.

Notwithstanding the preceding, without the consent of any Holder of Notes, the Issuers, the Subsidiary Guarantors and the trustee may amend or supplement the Indenture or the Notes:

(2) to provide for uncertificated Notes in addition to or in place of certificated Notes;

(3) to provide for the assumption of COO’s or any Subsidiary Guarantor’s obligations to Holders of Notes in the case of a merger or consolidation or sale of all or substantially all of COO’s or such Subsidiary Guarantor’s properties or assets, including the addition of any required co-issuer of the Notes;

(4) to make any change that would provide any additional rights or benefits to the Holders of Notes or that does not adversely affect the legal rights under the Indenture of any such Holder, provided that any change to conform the Indenture to the offering memorandum used in the initial issuance of the Notes will not be deemed to adversely affect such legal rights;

(5) to secure the Notes or the Subsidiary Guarantees pursuant to the requirements of the covenant described above under “—Certain Covenants—Liens;”

(6) to provide for the issuance of additional Notes in accordance with the limitations set forth in the Indenture;

(7) to add any additional Subsidiary Guarantor or to evidence the release of any Subsidiary Guarantor from its Subsidiary Guarantee or to add the guarantee of COO’s parent entity or to evidence the release of such entity’s guarantee, in each case as provided in the Indenture;

(8) to comply with requirements of the Commission in order to effect or maintain the qualification of the Indenture under the Trust Indenture Act;

(9) to provide for the reorganization of COO as any other form of entity in accordance with the second paragraph under “—Certain Covenants—Merger, Consolidation or Sales or Assets;”

(10) to evidence or provide for the acceptance of appointment under the Indenture of a successor trustee; or

(11) to conform the text of the Indenture or the Notes to any provision of this Description of the Notes to the extent that such provision in this Description of Notes was intended to be a substantially verbatim recitation of a provision of the Indenture, the Subsidiary Guarantees or the Notes.

The Indenture will be discharged and will cease to be of further effect as to all Notes issued thereunder (except as to surviving rights of registration of transfer or exchange of the Notes and as otherwise specified in the Indenture), when:

(a) all Notes that have been authenticated, except lost, stolen or destroyed Notes that have been replaced or paid and Notes for whose payment money has been deposited in trust and thereafter repaid to the Issuers, have been delivered to the trustee for cancellation; or

(b) all Notes that have not been delivered to the trustee for cancellation have become due and payable or will become due and payable within one year by reason of the mailing of a notice of redemption or otherwise and the Issuers or any Subsidiary Guarantor has irrevocably deposited or caused to be deposited with the trustee as trust funds in trust solely for the benefit of the Holders, cash in U.S. dollars, non-callable Government Securities, or a combination of cash in U.S. dollars and non-callable Government Securities, in amounts as will be sufficient without consideration of any reinvestment of interest, to pay and discharge the entire indebtedness on the Notes not delivered to the trustee for cancellation for principal, premium, if any, and accrued interest to the date of fixed maturity or redemption;

(2) no Default or Event of Default has occurred and is continuing on the date of the deposit or will occur as a result of the deposit (other than a Default or Event of Default resulting from the borrowing of funds to be applied to such deposit), and the deposit will not result in a breach or violation of, or constitute a default under, any material agreement or instrument (other than the Indenture) to which COO or any of its Subsidiaries is a party or by which COO or any of its Subsidiaries is bound;

(3) any of the Issuers or any Subsidiary Guarantor has paid or caused to be paid all sums payable by it under the Indenture; and

(4) the Issuers have delivered irrevocable instructions to the trustee under the Indenture to apply the deposited money toward the payment of the Notes at fixed maturity or on the redemption date, as the case may be.

In addition, the Issuers must deliver an officers’ certificate and an opinion of counsel to the trustee stating that all conditions precedent to satisfaction and discharge have been satisfied.

If the trustee becomes a creditor of the Issuers or any Subsidiary Guarantor, the Indenture limits its right to obtain payment of claims in certain cases, or to realize on certain property received in respect of any such claim as security or otherwise. The trustee will be permitted to engage in other transactions; however, if it acquires any conflicting interest (as defined in the Trust Indenture Act) after a Default has occurred and is continuing, it must eliminate such conflict within 90 days, apply to the Commission for permission to continue or resign.

The Holders of a majority in principal amount of the then outstanding Notes will have the right to direct the time, method and place of conducting any proceeding for exercising any remedy available to the trustee, subject to certain exceptions. The Indenture provides that in case an Event of Default occurs and is continuing, the trustee will be required, in the exercise of its power, to use the degree of care of a prudent man in the conduct of his own affairs. Subject to such provisions, the trustee will be under no obligation to exercise any of its rights or powers under the Indenture at the request of any Holder of Notes, unless such Holder has offered to the trustee security or indemnity satisfactory to it against any loss, liability or expense.

The Indenture, the Notes and the Subsidiary Guarantees are governed by, and will be construed in accordance with, the laws of the State of New York.

A Global Note is exchangeable for Certificated Notes in minimum denominations of $2,000 and in integral multiples of $1,000 in excess of $2,000, if:

(1) DTC (a) notifies the Issuers that it is unwilling or unable to continue as depositary for the Global Note or (b) has ceased to be a clearing agency registered under the Exchange Act and in either event the Issuers fail to appoint a successor depositary within 90 days; or

(2) there has occurred and is continuing an Event of Default and DTC notifies the trustee of its decision to exchange the Global Note for Certificated Notes.

Beneficial interests in a Global Note may also be exchanged for Certificated Notes in the other limited circumstances permitted by the Indenture, including if an affiliate of ours acquires such interests. In all cases, Certificated Notes delivered in exchange for any Global Note or beneficial interests in Global Notes will be registered in the names, and issued in any approved denominations, requested by or on behalf of the depositary (in accordance with its customary procedures) and will bear the restrictive legend referred to in “Notice to Investors,” unless that legend is not required by applicable law.

Certificated Notes may not be exchanged for beneficial interests in any Global Note.

Set forth below are certain defined terms used in the Indenture. Reference is made to the Indenture for a full disclosure of all such terms, as well as any other capitalized terms used herein for which no definition is provided.

(1) Indebtedness of any other Person existing at the time such other Person was merged with or into or became a Subsidiary of such specified Person, whether or not such Indebtedness is incurred in connection with, or in contemplation of, such other Person merging with or into, or becoming a Subsidiary of, such specified Person, but excluding Indebtedness which is extinguished, retired or repaid in connection with such Person merging with or into or becoming a Subsidiary of such specified Person; and

(2) Indebtedness secured by a Lien encumbering any asset acquired by such specified Person, but excluding Indebtedness that is extinguished, retired or repaid in connection with such Person merging with or becoming a Restricted Subsidiary of such specified Person.

“Affiliate “ of any specified Person means any other Person directly or indirectly controlling or controlled by or under direct or indirect common control with such specified Person. For purposes of this definition, “control,” as used with respect to any Person, means the possession, directly or indirectly, of the power to direct or cause the direction of the management or policies of such Person, whether through the ownership of voting securities, by agreement or otherwise; provided, however, that beneficial ownership of 10% or more of the Voting Stock of a Person will be deemed to be control by the Person that owns such beneficial ownership interest. For purposes of this definition, the terms “controlling,” “controlled by” and “under common control with” have correlative meanings.

(1) the sale, lease, conveyance, transfer, assignment or other disposition of any properties or assets (including by way of a sale and leaseback transaction or a merger or consolidation) other than in the ordinary course of business; provided that the disposition of all or substantially all of the properties or assets of COO and its Restricted Subsidiaries taken as a whole will be governed by the provisions described above under “—Repurchase at the Option of Holders—Change of Control” and/or the provisions described above under “—Certain Covenants—Merger, Consolidation or Sale of Assets” and not by the provisions described above under “—Repurchase at the Option of Holders—Asset Sales;” and

(2) the issuance of Equity Interests in any of COO’s Restricted Subsidiaries or the sale of Equity Interests in any of its Restricted Subsidiaries.

Notwithstanding the preceding, the following items will not be deemed to be Asset Sales:

(1) any single transaction or series of related transactions that involves properties or assets having a fair market value of less than $25.0 million;

(2) a transfer of assets between or among any of COO and its Restricted Subsidiaries;

(3) an issuance or sale of Equity Interests by a Restricted Subsidiary to COO or to another Restricted Subsidiary;

(4) the sale, lease or other disposition of inventory in the ordinary course of business;

(5) transfers, abandonment or relinquishment of damaged, worn-out or obsolete properties, equipment or assets that, in COO’s reasonable judgment, are no longer used or useful in the business of COO or its Restricted Subsidiaries;

(6) the sale, trade, exchange or other disposition of cash or Cash Equivalents, Hedging Obligations or other financial instruments in the ordinary course of business;

(7) the sale, exchange or disposition of accounts receivable in connection with the compromise, settlement or collection thereof in the ordinary course of business or in bankruptcy or similar proceedings, exclusive of factoring and similar arrangements;

(8) a Permitted Investment or a Restricted Payment that is permitted by the covenant described above under “—Certain Covenants—Restricted Payments;”

(9) any trade or exchange by COO or any Restricted Subsidiary of any properties or assets for properties or assets that are used or usable in a Permitted Business owned or held by another Person, provided that the fair market value of the properties or assets traded or exchanged by COO or such Restricted Subsidiary (together with any cash) is reasonably equivalent to the fair market value of the properties or assets (together with any cash) to be received by COO or such Restricted Subsidiary, and provided further that, subject to any other exceptions in this definition, any cash received must be applied in accordance with the provisions described above under “—Repurchase at the Option of Holders—Asset Sales;”

(10) the creation or perfection of Permitted Liens and Liens that are not prohibited by the covenant described above under “—Certain Covenants—Liens” and any disposition of assets from the enforcement or foreclosure of any such Liens;

(11) the surrender or waiver in the ordinary course of business of contract rights or the settlement, release or surrender of contract, tort or other claims of any kind;

(12) any damage or loss of any asset or property resulting in the payment of condemnation or insurance proceeds; and

(13) the grant in the ordinary course of business of any license of patents, trademarks, registrations therefor and other similar intellectual property.

“Attributable Debt” in respect of a sale and leaseback transaction means, at the time of determination, the present value of the obligation of the lessee for net rental payments during the remaining term of the lease included in such sale and leaseback transaction including any period for which such lease has been extended or may, at the option of the lessor, be extended. Such present value shall be calculated using a discount rate equal to the rate of interest implicit in such transaction, determined in accordance with GAAP. As used in the first sentence of this definition, the “net rental payments” under any lease for any such period shall mean the

sum of rental and other payments required to be paid with respect to such period by the lessee thereunder, excluding any amounts required to be paid by such lessee on account of maintenance and repairs, insurance, taxes, assessments, water rates or similar charges. In the case of any lease that is terminable by the lessee upon payment of penalty, such net rental payment shall also include the amount of such penalty, but no rent shall be considered as required to be paid under such lease subsequent to the first date upon which it may be so terminated. Notwithstanding the foregoing, the Attributable Debt with respect to each of the following sale and leaseback transactions shall, in each case, be zero:

(1) a sale and leaseback transaction in which the lease is for a period, including renewal rights, not in excess of three years;

(2) a sale and leaseback transaction with respect to any asset that occurs within 270 days of the acquisition or construction of, or the completion of a material improvement to, such asset;

(3) a sale and leaseback transaction in which the transaction is between or among COO and one or more Restricted Subsidiaries or between or among Restricted Subsidiaries; or

(4) a sale and leaseback transaction pursuant to which COO, within 270 days after the completion of the sale and leaseback transaction, applies toward the retirement of its Indebtedness or the Indebtedness of a Restricted Subsidiary, or to the purchase of other property, the greater of (i) the net proceeds from the sale and leaseback transaction or (ii) the fair market value of the assets sold in such transaction; provided, however, that the amount that must be applied to the retirement of Indebtedness shall be reduced by:

(a) the principal amount of any debentures, notes or debt securities (including the Notes) of COO or a Restricted Subsidiary surrendered to the applicable trustee or agent for retirement and cancellation within 270 days of the completion of the sale and leaseback transaction;

(b) the principal amount of any Indebtedness not included in clause (4)(a) of this definition to the extent such amount of Indebtedness is voluntarily retired by COO or a Restricted Subsidiary within 270 days of the completion of the sale and leaseback transaction; and

Any drilling rig subleases existing as of the Initial Issuance Date shall be treated as if they were leases in respect of a sale and leaseback transaction.

“Beneficial Owner” has the meaning assigned to such term in Rule 13d-3 and Rule 13d-5 under the Exchange Act, except that in calculating the beneficial ownership of any particular “person” (as that term is used in Section 13(d)(3) of the Exchange Act), such “person” will be deemed to have beneficial ownership of all securities that such “person” has the right to acquire by conversion or exercise of other securities, whether such right is currently exercisable or is exercisable only upon the occurrence of a subsequent condition. The terms “Beneficially Owns” and “Beneficially Owned” have correlative meanings.

(1) with respect to COO, its board of managers or other governing body or any authorized committee thereof; and

(2) with respect to any other Person, the board or committee of such Person, or its general partner, as applicable, serving a similar function.

“Board Resolution” means a copy of a resolution certified by the Secretary or an Assistant Secretary of the applicable Person to have been duly adopted by the Board of such Person and to be in full force and effect on the date of such certification, and delivered to the trustee.

“Business Day” means each day that is not a Saturday, Sunday or other day on which banking institutions in New York, New York or another place of payment are authorized or required by law to close.

“Capital Lease Obligation” means, at the time any determination is to be made, the amount of the liability in respect of a capital lease that would at that time be required to be capitalized on a balance sheet in accordance with GAAP. Notwithstanding the foregoing, if GAAP lease accounting rules amended or adopted after the Initial Issuance Date shall require a lease previously determined to be an operating lease to be recorded on a balance sheet in accordance with such rules, such lease shall not be a capital lease for purposes of the Indenture.

(2) in the case of an association or business entity, any and all shares, interests, participations, rights or other equivalents (however designated) of corporate stock;

(3) in the case of a partnership or limited liability company, partnership or membership interests (whether general or limited); and

(4) any other interest or participation that confers on a Person the right to receive a share of the profits and losses of, or distributions of assets of, the issuing Person.

(2) securities issued or directly and fully guaranteed or insured by the United States government or any agency or instrumentality of the United States government (provided that the full faith and credit of the United States is pledged in support of those securities) maturing within one year after the date of acquisition;

(3) certificates of deposit and Eurodollar time deposits with maturities of one year or less from the date of acquisition, bankers’ acceptances with maturities not exceeding one year from the date of acquisition and overnight bank deposits, in each case, with any lender party to the Credit Agreement or with any domestic commercial bank having capital and surplus in excess of $500.0 million and a Thomson Bank Watch Rating of “B” or better;

(4) repurchase obligations with a term of not more than seven days for underlying securities of the types described in clauses (2) and (3) above entered into with any financial institution meeting the qualifications specified in clause (3) above;

(5) commercial paper having one of the two highest ratings obtainable from Moody’s or S&P and in each case maturing within one year after the date of acquisition; and

(6) money market funds at least 95% of the assets of which constitute Cash Equivalents of the kinds described in clauses (1) through (5) of this definition.

(1) the direct or indirect sale, lease, transfer, conveyance or other disposition (other than by way of merger or consolidation), in one transaction or a series of related transactions, of all or substantially all of the properties or assets (including Capital Stock of the Restricted Subsidiaries) of COO and its Restricted Subsidiaries taken as a whole, to any “person” (as that term is used in Section 13(d)(3) of the Exchange Act) other than Chesapeake Energy Corporation or a Subsidiary thereof; or

(2) the adoption of a plan relating to the liquidation or dissolution of COO; or

(3) the consummation of any transaction (including, without limitation, any merger or consolidation) the result of which is that any “person” (as that term is used in Section 13(d)(3) of the Exchange Act), other than Chesapeake Energy Corporation or a Subsidiary thereof, becomes the Beneficial Owner, directly or indirectly, of more than 50% of the Voting Stock of COO, measured by voting power rather than number of shares, units or the like.

Notwithstanding the preceding, a conversion of COO or any of its Restricted Subsidiaries from a limited partnership, corporation, limited liability company or other form of entity to a limited partnership, corporation, limited liability company or other form of entity or an exchange of all of the outstanding Equity Interests in one form of entity for Equity Interests in another form of entity shall not constitute a Change of Control, so long as following such conversion or exchange the “persons” (as that term is used in Section 13(d)(3) of the Exchange Act) who Beneficially Owned the Capital Stock of COO immediately prior to such transactions continue to Beneficially Own in the aggregate more than 50% of the Voting Stock of such entity, or continue to Beneficially Own sufficient Equity Interests in such entity to elect a majority of its directors, managers, trustees or other persons serving in a similar capacity for such entity, and, in either case no “person,” other than Chesapeake Energy Corporation or a Subsidiary thereof, Beneficially Owns more than 50% of the Voting Stock of such entity.

“Code” means the Internal Revenue Code of 1986, as amended from time to time, and any successor statute.

“Common Stock” means, with respect to any Person, any Capital Stock (other than Preferred Stock) of such Person.

“Consolidated Cash Flow” means, with respect to any specified Person for any period, the Consolidated Net Income of such Person for such period plus:

(1) an amount equal to any net loss realized by such Person or any of its Restricted Subsidiaries in connection with an Asset Sale, to the extent such losses were deducted in computing such Consolidated Net Income; plus

(2) amounts required to be dividended, paid or otherwise distributed pursuant to a tax sharing or other agreement, by COO, on behalf of itself and its Restricted Subsidiaries, for taxes incurred with respect to income or profits of such entities but payable by a direct or indirect owner of COO, to the extent such amounts were deducted in computing Consolidated Net Income; plus

(3) Fixed Charges of such Person for such period, to the extent that such Fixed Charges were deducted in computing such Consolidated Net Income; plus

(4) depreciation and amortization (including amortization of intangibles but excluding amortization of prepaid cash expenses that were paid in a prior period), impairment and other non-cash charges or expenses (excluding any such non-cash expense to the extent that it represents an accrual of or reserve for cash expenses in any future period or amortization of a prepaid cash expense that was paid in a prior period) of such Person and its Restricted Subsidiaries for such period to the extent that such depreciation and amortization, impairment and other non-cash charges or expenses were deducted in computing such Consolidated Net Income; plus

(5) unrealized non-cash losses of such Person and its Restricted Subsidiaries resulting from foreign currency balance sheet adjustments required by GAAP to the extent such losses were deducted in computing such Consolidated Net Income; plus

(6) all extraordinary, unusual or non-recurring items of loss or expense of such Person and its Restricted Subsidiaries (whether or not includable as a separate line item in the financial statements of such Person); minus

(7) all non-cash items of gain and extraordinary items of gain increasing such Consolidated Net Income for such period, in each case, on a consolidated basis and determined in accordance with GAAP.

“Consolidated Net Income” means, with respect to any specified Person for any period, the aggregate of the net income of such Person and its Restricted Subsidiaries for such period, on a consolidated basis, determined in accordance with GAAP; provided that:

(1) the net income (but not loss) of any Person that is not a Restricted Subsidiary or that is accounted for by the equity method of accounting will be included, but only to the extent of the amount of dividends or distributions paid in cash to the specified Person or a Restricted Subsidiary of the Person;

(2) the net income of any Restricted Subsidiary (other than a Subsidiary Guarantor) will be excluded to the extent that the declaration or payment of dividends or similar distributions by that Restricted Subsidiary of that net income is not at the date of determination permitted without any prior governmental approval (that has not been obtained) or, directly or indirectly, by operation of the terms of its charter or any agreement, instrument, judgment, decree, order, statute, rule or governmental regulation applicable to that Restricted Subsidiary or its stockholders, partners or members, unless such restriction with respect to the payment of dividends has been legally waived;

(3) the cumulative effect of a change in accounting principles will be excluded;

(4) unrealized losses and gains from derivative instruments included in the determination of Consolidated Net Income, including, without limitation those resulting from the application of FASB Accounting Standards Codification (ASC) 815 will be excluded; and

(5) any write-down of non-current assets and any nonrecurring charges relating to any premium or penalty paid, write off of deferred finance costs or other charges in connection with redeeming or retiring any Indebtedness prior to its Stated Maturity will be excluded.

“Consolidated Tangible Assets” means, with respect to any Person at any date of determination, the aggregate amount of total assets included in such Person’s most recent quarterly or annual consolidated balance sheet prepared in accordance with GAAP less applicable reserves reflected in such balance sheet, after deducting the amount of all goodwill, trademarks, patents, unamortized debt discounts and expenses and any other like intangibles reflected in such balance sheet.

“Credit Agreement” means that certain Credit Agreement, entered into on or about the Initial Issuance Date, among COO, the subsidiary guarantor parties thereto, the lenders party thereto and Bank of America, N.A., as administrative agent, including any related notes, guarantees, collateral documents, instruments and agreements executed in connection therewith, and in each case as amended, restated, modified, renewed, refunded, replaced or refinanced from time to time.

“Credit Facilities” means one or more debt facilities (including, without limitation, the Credit Agreement), commercial paper facilities or other agreements, in each case with banks, investment banks, insurance companies, mutual funds, hedge funds and/or other institutional lenders providing for revolving credit loans, term loans, receivables financing (including through the sale of receivables to such lenders or other financiers or to special purpose entities formed to borrow from (or sell receivables to) such lenders against such receivables) or letters of credit, in each case, as amended, extended, restated, renewed, refunded, replaced (whether contemporaneously or otherwise) or refinanced (in each case with Credit Facilities), supplemented or otherwise modified (in whole or in part and without limitation as to amount, terms, conditions, covenants and other provisions) from time to time.

“Default” means any event that is, or with the passage of time or the giving of notice or both would be, an Event of Default.

“Designated Non-cash Consideration” means the fair market value of non-cash consideration received by COO or a Restricted Subsidiary in connection with an Asset Sale that is so designated as Designated Non-cash Consideration pursuant to an officers’ certificate, setting forth the basis of such valuation, executed by the principal financial officer of COO, less the amount of cash or Cash Equivalents received in connection with a subsequent sale of or collection on such Designated Non-cash Consideration.

“Designated Proceeds” means the amount of net cash proceeds received by COO from each issuance or sale since the Initial Issuance Date of Preferred Stock of COO (other than Disqualified Stock), that at the time of such issuance was designated by COO as Designated Proceeds pursuant to an officers’ certificate delivered to the trustee; provided, however, that if the Preferred Stock providing such Designated Proceeds is thereafter converted into Common Stock of COO, that portion of the Designated Proceeds that has not been paid as dividends pursuant to clause (11) of the second paragraph of the covenant described above under “—Certain Covenants—Restricted Payments” will no longer be considered to be Designated Proceeds.

“Disqualified Stock” means any Capital Stock that, by its terms (or by the terms of any security into which it is convertible, or for which it is exchangeable, in each case at the option of the holder of the Capital Stock), or upon the happening of any event, matures or is mandatorily redeemable, pursuant to a sinking fund obligation or otherwise, or redeemable at the option of the holder of the Capital Stock, in whole or in part, on or prior to the date that is 91 days after the date on which the Notes mature, unless such Capital Stock is redeemable solely in exchange for Capital Stock that is not Disqualified Stock. Notwithstanding the preceding sentence, any Capital Stock that would constitute Disqualified Stock solely because the holders of the Capital Stock have the right to require COO to repurchase or redeem such Capital Stock upon the occurrence of a change of control or an asset sale will not constitute Disqualified Stock if the terms of such Capital Stock are no more favorable in any material respect to such holders than the provisions described above under “—Repurchase at the Option of Holders—Change of Control” and “—Repurchase at the Option of Holders—Asset Sales,” respectively, and such Capital Stock specifically provides that COO may only repurchase or redeem any such Capital Stock pursuant to such provisions only after COO’s purchase of the Notes as required pursuant to the provisions described above under “—Repurchase at the Option of Holders—Change of Control” and “—Repurchase at the Option of Holders—Asset Sales,” respectively.

“Equity Interests” means Capital Stock and all warrants, options or other rights to acquire Capital Stock (but excluding any debt security that is convertible into, or exchangeable for, Capital Stock).

“Equity Offering” means any public or private sale for cash of Capital Stock (other than Disqualified Stock) of COO or of COO’s direct parent to the extent the net cash proceeds are contributed to COO.

“Existing Indebtedness” means the aggregate principal amount of Indebtedness of COO and its Restricted Subsidiaries (other than (i) Indebtedness under the Credit Agreement, (ii) the Notes issued and sold on the Initial Issuance Date and the related Subsidiary Guarantees and (iii) intercompany Indebtedness, which are considered incurred under clauses (1), (3) and (6), respectively, of the second paragraph of the covenant described above under “—Certain Covenants—Incurrence of Indebtedness and Issuance of Preferred Stock”) in existence on the date of the Indenture, until such amounts are repaid.

“fair market value” means, with respect to any asset, property or security (other than a publicly traded security, for which the fair market value is determined by reference to the most recent closing price for such security on the national securities exchange on which such security is listed or admitted to trading), the price in cash (after taking into account any liabilities relating to such asset) that would be negotiated in an arm’s-length transaction for cash between a willing seller and a willing and able buyer, neither of which is under any compulsion to complete the transaction as such price is determined in good faith by (a) in the case of any asset, property or security the price for which would be greater than $50.0 million, the Board of COO or a duly authorized committee thereof, as evidenced by a resolution of such Board or committee and (b) in all other cases, by the Chief Financial Officer or the Chief Executive Officer of COO.

“Fixed Charge Coverage Ratio” means with respect to any specified Person for any four-quarter reference period (or such shorter period as provided in clause (5) of the next succeeding paragraph below), the ratio of the Consolidated Cash Flow of such Person for such period to the Fixed Charges of such Person for such period. If the specified Person or any of its Restricted Subsidiaries incurs, assumes, guarantees, repays, repurchases or redeems any Indebtedness (other than the incurrence or repayment of Indebtedness in the ordinary course of business for working capital purposes pursuant to any revolving credit arrangement) or issues, repurchases or redeems Preferred Stock subsequent to the commencement of the applicable reference period and on or prior to the date on which the event for which the calculation of the Fixed Charge Coverage Ratio is made (the “Calculation Date”), then the Fixed Charge Coverage Ratio will be calculated giving pro forma effect to such incurrence, assumption, guarantee, repayment, repurchase or redemption of Indebtedness, or such issuance, repurchase or redemption of Preferred Stock, and the use of the proceeds therefrom as if the same had occurred at the beginning of such period.

(1) acquisitions and dispositions of business entities or property and assets constituting a division or line of business of any Person that have been made by the specified Person or any of its Restricted Subsidiaries, including through mergers, consolidations or otherwise, and including in each case any related financing transactions (including repayment of Indebtedness) during the applicable reference period or subsequent to such reference period and on or prior to the Calculation Date, will be given pro forma effect as if they had occurred on the first day of the applicable reference period, including any Consolidated Cash Flow and any pro forma expense and cost reductions that have occurred or are reasonably expected to occur, in the reasonable good faith judgment of the chief financial or accounting officer of COO (regardless of whether those cost savings or operating improvements could then be reflected in pro forma financial statements in accordance with Regulation S-X promulgated under the Securities Act or any other regulation or policy of the Commission related thereto);

(2) the Consolidated Cash Flow attributable to discontinued operations, as determined in accordance with GAAP, will be excluded;

(3) the Fixed Charges attributable to discontinued operations, as determined in accordance with GAAP, and operations or businesses disposed of prior to the Calculation Date, will be excluded, but only to the extent that the obligations giving rise to such Fixed Charges will not be obligations of the specified Person or any of its Restricted Subsidiaries following the Calculation Date;

(4) interest income reasonably anticipated by such Person to be received during the applicable reference period from cash or Cash Equivalents held by such Person or any Restricted Subsidiary of such Person, which cash or Cash Equivalents exist on the Calculation Date or will exist as a result of the transaction giving rise to the need to calculate the Fixed Charge Coverage Ratio, will be included;

(5) if the Calculation Date occurs within any period ending on or before March 31, 2012 for which internal financial statements for the immediately preceding four full fiscal quarters are not available, then the applicable reference period with respect to such Calculation Date shall be the number of full fiscal quarters for which such financial statements are available;

(6) Fixed Charges attributable to interest on any Indebtedness (whether existing or being Incurred) computed on a pro forma basis and bearing a floating interest rate will be computed as if the rate in effect on the Calculation Date (taking into account any interest rate option, swap, cap or similar agreement applicable to such Indebtedness if such agreement has a remaining term in excess of 12 months or, if shorter, at least equal to the remaining term of such Indebtedness) had been the applicable rate for the entire period; and

(7) Fixed Charges attributable to interest on any Indebtedness incurred under a revolving credit facility computed on a pro forma basis will be calculated based on the average daily balance of such Indebtedness for the four fiscal quarters subject to the pro forma calculation to the extent that such Indebtedness was Incurred solely for working capital purposes.

“Fixed Charges” means, with respect to any specified Person for any period, the sum, without duplication, of:

(1) the consolidated interest expense of such Person and its Restricted Subsidiaries for such period, whether paid or accrued (including, without limitation, amortization of debt issuance costs and original issue discount, non-cash interest payments, the interest component of any deferred payment obligations, the interest component of all payments associated with Capital Lease Obligations, imputed interest with respect to Attributable Debt, commissions, discounts and other fees and charges incurred in respect of letter of credit or bankers’ acceptance financings), and net of the effect of all payments made or received pursuant to interest rate Hedging Obligations; plus

(2) the consolidated interest expense of such Person and its Restricted Subsidiaries that was capitalized during such period; plus

(3) any interest expense on Indebtedness of another Person that is guaranteed by such Person or one of its Restricted Subsidiaries or secured by a Lien on assets of such Person or one of its Restricted Subsidiaries, whether or not such guarantee or Lien is called upon; plus

(4) all dividends, whether paid or accrued and whether or not in cash, on any series of Preferred Stock of such Person or any of its Restricted Subsidiaries, other than dividends on Equity Interests payable solely in Equity Interests of COO (other than Disqualified Stock) or to COO or a Restricted Subsidiary of COO,

“Foreign Subsidiary” means any Restricted Subsidiary of COO (1) that is organized or incorporated outside the United States or any territory thereof and (2) that has 50% or more of its consolidated assets located outside the United States or any territory thereof.

“GAAP” means generally accepted accounting principles in the United States, which are in effect from time to time.

The term “guarantee” means a guarantee other than by endorsement of negotiable instruments for collection in the ordinary course of business, direct or indirect, in any manner including, without limitation, by way of a pledge of assets or through letters of credit or reimbursement agreements in respect thereof, of all or any part of any Indebtedness. When used as a verb, “guarantee” has a correlative meaning.

“Hedging Obligations” means, with respect to any specified Person, the obligations of such Person under:

(1) interest rate swap agreements, interest rate options, interest rate swaption agreements, interest rate cap agreements and interest rate collar agreements entered into with one of more financial institutions and designed to protect the Person or any of its Restricted Subsidiaries entering into the agreement against fluctuations in or to otherwise manage exposure to interest rates with respect to Indebtedness incurred;

(2) foreign exchange contracts and currency protection agreements entered into with one of more financial institutions and designed to protect the Person or any of its Restricted Subsidiaries entering into the agreement against fluctuations in currency exchanges rates with respect to Indebtedness incurred;

(3) any commodity futures contract, commodity option or other similar agreement or arrangement designed to protect against fluctuations in the price of Hydrocarbons used, produced, processed or sold by that Person or any of its Restricted Subsidiaries at the time; and

(4) other agreements or arrangements designed to protect such Person or any of its Restricted Subsidiaries against fluctuations in or to otherwise manage exposure to interest rates, commodity prices or currency exchange rates.

“Hydrocarbons” means crude oil, natural gas, casinghead gas, drip gasoline, natural gasoline, condensate, distillate, liquid hydrocarbons, gaseous hydrocarbons and all constituents, elements or compounds thereof and products refined or processed therefrom.

“Indebtedness” means, with respect to any specified Person, without duplication:

(1) all liabilities, contingent or otherwise, of such Person in respect of borrowed money;

(2) all obligations of such Person evidenced by bonds, notes, debentures or similar instruments;

(3) all reimbursement obligations of such Person in respect of letters of credit or bankers’ acceptances;

(6) obligations of such Person for the payment of the balance deferred and unpaid of the purchase price of any property or services, except any such balance that constitutes deferred compensation, an accrued expense or trade payable incurred by such Person in the ordinary course of business in connection with obtaining goods, materials or services and not overdue by more than 180 days unless subject to a bona fide dispute; and

if and to the extent any of the preceding items (other than the item referred to in clause (5), letters of credit, bankers’ acceptances and Hedging Obligations) would appear as a liability upon a balance sheet of the specified Person prepared in accordance with GAAP. In addition, the term “Indebtedness” includes (x) all Indebtedness of others secured by a Lien on any asset of the specified Person (whether or not such Indebtedness is assumed by the specified Person) but in an amount not to exceed the lesser of the amount of such other Person’s Indebtedness or the fair market value of such asset and (y) to the extent not otherwise included, the guarantee by the specified Person of any Indebtedness of any other Person, whether or not such guarantee is contingent, and whether or not such guarantee appears on the balance sheet of such Person.

(1) the accreted value of the Indebtedness, in the case of any Indebtedness issued with original issue discount; and

(2) the principal amount of the Indebtedness, together with any interest on the Indebtedness that is more than 30 days past due, in the case of any other Indebtedness.

“Initial Issuance Date” means the date the Notes were initially issued under the Indenture.

“Investment Grade Rating” means a rating equal to or higher than Baa3 (or the equivalent) by Moody’s or BBB- (or the equivalent) by S&P.

“Investments” means, with respect to any Person, all direct or indirect investments by such Person in other Persons (including Affiliates) in the forms of loans (including guarantees of Indebtedness or other obligations), advances, capital contributions or extension of credit (excluding (1) commission, travel and similar advances to officers and employees made in the ordinary course of business and (2) advances to customers in the ordinary course of business that are recorded as accounts receivable on the balance sheet of the lender), purchases or other acquisitions for consideration of Indebtedness, Equity Interests or other securities, together with all items that are or would be classified as investments on a balance sheet prepared in accordance with GAAP. If COO or any Restricted Subsidiary sells or otherwise disposes of any Equity Interests of any Restricted Subsidiary such that, after giving effect to any such sale or disposition, such Person is no longer a Restricted Subsidiary, COO will be deemed to have made an Investment on the date of any such sale or disposition in an amount equal to the fair market value of the Equity Interests of such Restricted Subsidiary not sold or disposed of. The acquisition by COO or any Restricted Subsidiary of a Person that holds an Investment in a third Person will be deemed to be an Investment by COO or such Restricted Subsidiary in such third Person in an amount equal to the fair market value of the Investment held by the acquired Person in such third Person on the date of such acquisition.

“Joint Venture” means any Person that is not a direct or indirect Subsidiary of COO in which COO or any of its Restricted Subsidiaries makes any Investment.

“Lien” means, with respect to any asset, any mortgage, lien, pledge, security interest or similar encumbrance in respect of such asset, whether or not filed, recorded or otherwise perfected under applicable law, including any conditional sale or other title retention agreement and any filing of or agreement to give any financing statement under the Uniform Commercial Code (or equivalent statutes) of any jurisdiction other than a precautionary financing statement respecting a lease not intended as a security agreement. In no event will a right of first refusal be deemed to constitute a Lien.

“Moody’s” means Moody’s Investors Service, Inc. or any successor to the rating agency business thereof.

“Net Proceeds” means the aggregate cash proceeds received by COO or any of its Restricted Subsidiaries in respect of any Asset Sale (including, without limitation, any cash received prior to the date upon which Net Proceeds are being determined upon the sale or other disposition of any non-cash consideration received in any Asset Sale), net of:

(1) the direct costs relating to such Asset Sale, including, without limitation, legal, accounting and investment banking fees and expenses, sales commissions, any relocation expenses and any severance, change of control or similar payments incurred as a result of the Asset Sale,

(2) taxes paid or payable as a result of the Asset Sale, in each case, after taking into account any available tax credits or deductions and any tax sharing arrangements,

(3) amounts required to be applied to the repayment of Indebtedness secured by a Lien on the properties or assets that were the subject of such Asset Sale, and

(4) any amounts to be set aside in any reserve established in accordance with GAAP or any amount placed in escrow, in either case for adjustment in respect of the sale price of such properties or assets or for liabilities associated with such Asset Sale and retained by COO or any of its Restricted Subsidiaries until such time as such reserve is reversed or such escrow arrangement is terminated, in which case Net Proceeds shall include only the amount of the reserve so reversed or the amount returned to COO or its Restricted Subsidiaries from such escrow arrangement, as the case may be.

(1) as to which neither COO nor any of its Restricted Subsidiaries (a) provides credit support of any kind (including any undertaking, agreement or instrument that would constitute Indebtedness) or (b) is directly or indirectly liable as a guarantor or otherwise; and

(2) no default with respect to which (including any rights that the holders of the Indebtedness may have to take enforcement action against an Unrestricted Subsidiary) would permit upon notice, lapse of time or both any holder of any Indebtedness (other than the Notes) of COO or any of its Restricted Subsidiaries to declare a default on such other Indebtedness or cause the payment of such other Indebtedness to be accelerated or payable prior to its Stated Maturity.

For purposes of determining compliance with the covenant described under “—Certain Covenants—Incurrence of Indebtedness and Issuance of Preferred Stock” above, in the event that any Non-Recourse Debt of any of COO’s Unrestricted Subsidiaries ceases to be Non-Recourse Debt of such Unrestricted Subsidiary, such event will be deemed to constitute an incurrence of Indebtedness by a Restricted Subsidiary of COO.

“Obligations” means any principal, premium, if any, interest (including interest accruing on or after the filing of any petition in bankruptcy or for reorganization, whether or not a claim for post-filing interest is allowed in such proceeding), penalties, fees, charges, expenses, indemnifications, reimbursement obligations, damages, guarantees, and other liabilities or amounts payable under the documentation governing any Indebtedness or in respect thereto.

“Permitted Acquisition Indebtedness” means Indebtedness or Disqualified Stock of COO or any of its Restricted Subsidiaries to the extent such Indebtedness or Disqualified Stock was Indebtedness or Disqualified Stock of (i) a Subsidiary prior to

the date on which such Subsidiary became a Restricted Subsidiary or (ii) a Person that merged or consolidated with or into COO or a Restricted Subsidiary; provided that on the date such Subsidiary became a Restricted Subsidiary or the date such Person was merged or consolidated with or into COO or a Restricted Subsidiary, as applicable, after giving pro forma effect thereto, (a) COO would be permitted to incur at least $1.00 of additional Indebtedness pursuant to the Fixed Charge Coverage Ratio test set forth in the covenant described under “—Certain Covenants—Incurrence of Indebtedness and Issuance of Preferred Stock” or (b) the Fixed Charge Coverage Ratio for COO would be greater than the Fixed Charge Coverage Ratio for COO immediately prior to such transaction.

“Permitted Business” means the lines of business conducted by COO and its Restricted Subsidiaries on the date of the Indenture, any business incidental or reasonably related thereto and any reasonable extension thereof.

(1) any Investment in COO or in a Restricted Subsidiary of COO (including through purchases of Notes or other Indebtedness);

(3) any Investment by COO or any Restricted Subsidiary of COO in a Person, if as a result of such Investment:

(b) such Person is merged, consolidated or amalgamated with or into, or transfers or conveys substantially all of its properties or assets to, or is liquidated into, COO or a Restricted Subsidiary of COO;

(4) any Investment made as a result of the receipt of non-cash consideration from:

(a) an Asset Sale that was made pursuant to and in compliance with the covenant described above under “—Repurchase at the Option of Holders—Asset Sales;” or

(b) a transaction under clause (9) of the items deemed not to be Asset Sales under the definition of “Asset Sale;”

(5) any Investment in any Person to the extent received in exchange for the issuance of Equity Interests (other than Disqualified Stock) of COO or any Restricted Subsidiary;

(6) any Investments received in settlement of obligations of trade creditors or customers that were incurred in the ordinary course of business, including pursuant to any plan of reorganization or similar arrangement upon the bankruptcy or insolvency of any trade creditor or customer, or as a result of a foreclosure by COO or any of its Restricted Subsidiaries with respect to any secured Investment in default;

(7) Hedging Obligations permitted to be incurred under clause (7) of the second paragraph of the covenant described above under “—Certain Covenants—Incurrence of Indebtedness and Issuance of Preferred Stock;”

(8) Investments in the form of, or pursuant to, Joint Venture and partnership agreements, and Investments and expenditures in connection therewith or pursuant thereto, and having an aggregate fair market value (measured on the date each such Investment was made and without giving effect to subsequent changes in value), when taken together with all other Investments made pursuant to this clause (8) that are at the time outstanding, do not exceed the greater of $75.0 million or 5.0% of COO’s Consolidated Tangible Assets;

(9) Investments owned by any Person at the time such Person merges with or into COO or a Restricted Subsidiary or is acquired by COO or a Restricted Subsidiary, provided such Investments (a) are not incurred in contemplation of such merger or acquisition and (b) are, in the good faith determination of COO, incidental to such merger or acquisition, and in each case renewals or extensions thereof in amounts not greater than the amount of such Investment; and

(10) other Investments having an aggregate fair market value (measured on the date each such Investment was made and without giving effect to subsequent changes in value), when taken together with all other Investments made pursuant to this clause (10) that are at the time outstanding, do not exceed the greater of $75.0 million or 5.0% of COO’s Consolidated Tangible Assets.

(1) Liens securing any Indebtedness under any Credit Facility permitted to be incurred under the Indenture pursuant to clause (1) of the second paragraph of the covenant described above under “—Certain Covenants—Incurrence of Indebtedness and Issuance of Preferred Stock” and related Hedging Obligations;

(3) Liens on property, assets or capital stock of a Person existing at the time such Person is merged with or into or consolidated with COO or any Restricted Subsidiary of COO, provided that such Liens were not incurred in contemplation of such merger or consolidation and do not extend to any property or assets (other than improvements thereon, accessions thereto or proceeds thereof) other than those of the Person merged into or consolidated with COO or the Restricted Subsidiary;

(4) Liens on property or assets existing at the time of acquisition of the property or assets by COO or any Restricted Subsidiary of COO, provided that such Liens were in existence prior to the contemplation of such acquisition;

(5) any interest or title of a lessor to the property subject to a Capital Lease Obligation, sale and leaseback transaction or operating lease;

(6) Liens on any property or asset acquired, constructed or improved by COO or any of its Restricted Subsidiaries (a “Purchase Money Lien”) securing Indebtedness permitted under clause (4) of the second paragraph of the covenant described above under “—Certain Covenants—Incurrence of Indebtedness and Issuance of Preferred Stock,” which (a) are in favor of the seller of such property or assets, in favor of the Person developing, constructing, repairing or improving such asset or property, or in favor of the Person that provided the funding for the acquisition, development, construction, repair or improvement cost, as the case may be, of such asset or property, (b) are created within 360 days after the acquisition, development, construction, repair or improvement, (c) secure the purchase price or development, construction, repair or improvement cost, as the case may be, of such asset or property in an amount up to the cost of such acquisition, construction or improvement of such asset or property, and (d) are limited to the asset or property so acquired, constructed or improved (including the proceeds thereof, accessions thereto and upgrades thereof);

(7) Liens existing on the date of the Indenture securing Indebtedness outstanding on the date of the Indenture; provided that (i) the aggregate principal amount of the Indebtedness secured by such Liens does not increase; and (ii) such Liens do not encumber any property other than the property subject thereto on the date of the Indenture (plus improvements, accessions, proceeds or dividends or distributions in respect thereof);

(8) Liens to secure the performance of tenders, bids, statutory obligations, surety or appeal bonds, government contracts, performance bonds or other obligations of a like nature incurred in the ordinary course of business which were not incurred or created to secure Indebtedness for borrowed money;

(9) Liens on and pledges of the Equity Interests of any Unrestricted Subsidiary or any Joint Venture owned by COO or any Restricted Subsidiary of COO to the extent securing Non-Recourse Debt or other Indebtedness of such Unrestricted Subsidiary or Joint Venture;

(11) Liens for taxes, assessments or governmental charges or claims that are not yet delinquent or that are being contested in good faith by appropriate proceedings diligently pursued, provided that any reserve or other appropriate provision as is required in conformity with GAAP has been made therefor;

(12) carriers’, warehousemen’s, mechanics’, materialmen’s, repairman’s or other like Liens arising in the ordinary course of business;

(13) Liens arising under operating agreements, joint venture agreements, partnership agreements, master service agreements, oil and gas leases, farmout agreements, division orders, contracts for sale, transportation or exchange of crude oil and natural gas, unitization and pooling declarations and agreements, area of mutual interest agreements and other agreements arising in the ordinary course of business of COO and its Restricted Subsidiaries, which Liens (i) only cover the assets that relate to the applicable agreement and (ii) were not incurred or created to secure Indebtedness for borrowed money;

(14) Liens upon specific items of inventory, receivables or other goods or proceeds of COO or any of its Restricted Subsidiaries securing such Person’s obligations in respect of bankers’ acceptances or receivables securitizations issued or created for the account of such Person to facilitate the purchase, shipment or storage of such inventory, receivables or other goods or proceeds and permitted by the covenant described above under “—Certain Covenants—Incurrence of Indebtedness and Issuance of Preferred Stock;”

(15) Liens to secure any Permitted Refinancing Indebtedness permitted to be incurred under the Indenture; provided that (a) the new Lien shall be limited to all or part of the same property or assets that secured or, under the written agreements pursuant to which the original Lien arose, could secure the original Lien (plus improvements and accessions to, such property or assets or proceeds or distributions thereof) and (b) the Indebtedness secured by the new Lien is not increased to any amount greater than the sum of (x) the outstanding principal amount, or, if greater, committed amount, of the Permitted Refinancing Indebtedness and (y) an amount necessary to pay any fees and expenses, including premiums, related to such renewal, refunding, refinancing, replacement, defeasance or discharge;

(16) any Lien resulting from the deposit of money or other Cash Equivalents or other evidence of indebtedness in trust for the purpose of defeasing Indebtedness of COO or any Restricted Subsidiary;

(17) Liens securing Obligations of COO or any Subsidiary Guarantor under the Notes or the Subsidiary Guarantees, as the case may be;

(18) Liens securing any Indebtedness equally and ratably with all Obligations due under the Notes or any Subsidiary Guarantee pursuant to a contractual covenant that limits Liens in a manner substantially similar to the covenant described above under “—Certain Covenants—Liens;”

(19) Liens to secure Hedging Obligations of COO or any of its Restricted Subsidiaries entered into for bona fide hedging purposes and not for speculative purposes;

(20) Liens securing Indebtedness that does not exceed in principal amount (or accreted value, as applicable) at any one time outstanding the greater of (a) $20.0 million or (b) 5.0% of COO’s Consolidated Tangible Assets determined at the time of incurrence of such Indebtedness; and

(21) any Lien renewing, extending, refinancing or refunding a Lien permitted by clauses (1) through (20) above; provided that (a) the principal amount of the Indebtedness secured by such Lien is not increased and (b) no assets encumbered by any such Lien other than the assets permitted to be encumbered immediately prior to such renewal, extension, refinance or refund are encumbered thereby.

“Permitted Refinancing Indebtedness” means any Indebtedness of COO or any of its Restricted Subsidiaries, or portion of such Indebtedness, issued in exchange for, or the net proceeds of which are used to extend, refinance, renew, replace, defease or refund other Indebtedness of COO or any of its Restricted Subsidiaries (other than intercompany Indebtedness), including Indebtedness that extends, refinances, renews, replaces, defeases or refunds Permitted Refinancing Indebtedness; provided that:

(1) the principal amount (or accreted value, if applicable) of such Permitted Refinancing Indebtedness does not exceed the principal amount (or accreted value, if applicable) of the Indebtedness being extended, refinanced, renewed, replaced, defeased or refunded (plus all accrued interest on the Indebtedness and the amount of all expenses and premiums incurred in connection therewith);

(2) such Permitted Refinancing Indebtedness has a final maturity date no earlier than the final maturity date of, and has a Weighted Average Life to Maturity equal to or greater than the Weighted Average Life to Maturity of, the Indebtedness being extended, refinanced, renewed, replaced, defeased or refunded;

(3) if the Indebtedness being extended, refinanced, renewed, replaced, defeased or refunded is subordinated in right of payment to the Notes or the Subsidiary Guarantees, such Permitted Refinancing Indebtedness is subordinated in right of payment to the Notes or the Subsidiary Guarantees on terms at least as favorable to the Holders of Notes as those contained in the documentation governing the Indebtedness being extended, refinanced, renewed, replaced, defeased or refunded; and

(4) such Indebtedness is not incurred by a Restricted Subsidiary other than a Subsidiary Guarantor if COO or a Subsidiary Guarantor is the obligor on the Indebtedness being extended, refinanced, renewed, replaced, defeased or refunded.

Notwithstanding the preceding, any Indebtedness incurred under Credit Facilities pursuant to the covenant described above under “—Certain Covenants—Incurrence of Indebtedness and Issuance of Preferred Stock” shall be subject only to the refinancing provision in the definition of Credit Facilities and not pursuant to the requirements set forth in the definition of Permitted Refinancing Indebtedness.

“Person” means any individual, corporation, partnership, joint venture, association, joint-stock company, trust, unincorporated organization, limited liability company or government or other entity.

“Preferred Stock” means, with respect to any Person, any and all preferred or preference stock or other Equity Interests (however designated) of such Person that is preferred as to the payment of dividends upon liquidation, dissolution or winding up.

“Qualifying Credit Facility” means a Credit Facility providing for minimum revolving commitments of at least $300 million.

“Restricted Investment” means an Investment other than a Permitted Investment.

“Restricted Subsidiary” of a Person means any Subsidiary of such Person that is not an Unrestricted Subsidiary.

“S&P” refers to Standard & Poor’s Ratings Services, a division of The McGraw-Hill Companies, Inc., or any successor to the rating agency business thereof.

(1) any Indebtedness of COO or any Restricted Subsidiary permitted to be incurred under the terms of the Indenture, unless the instrument under which such Indebtedness is incurred expressly provides that it is subordinated in right of payment to the Notes or any Subsidiary Guarantee; and

(2) all Obligations with respect to the items listed in the preceding clause (1).

Notwithstanding anything to the contrary in the preceding sentence, Senior Indebtedness will not include:

For the avoidance of doubt, “Senior Indebtedness” will not include any trade payables or taxes owed or owing by COO or any Restricted Subsidiary.

“Significant Subsidiary” means any Subsidiary that would be a “significant subsidiary” as defined in Article 1, Rule 1-02 of Regulation S-X, promulgated pursuant to the Securities Act, as such Regulation is in effect on the date of the Indenture.

“Stated Maturity” means, with respect to any installment of interest or principal on any series of Indebtedness, the date on which the payment of interest or principal was scheduled to be paid in the original documentation governing such Indebtedness, and will not include any contingent obligations to repay, redeem or repurchase any such interest or principal prior to the date originally scheduled for the payment thereof.

“Subordinated Indebtedness” means Indebtedness of COO or its Restricted Subsidiaries that are expressly subordinated in right of payment to the Notes or Subsidiary Guarantees, as the case may be.

“Subordinated Obligations” means Obligations of COO or its Restricted Subsidiaries that are expressly subordinated in right of payment to the Notes or Subsidiary Guarantees, as the case may be.

(1) any corporation, association or other business entity (other than a partnership or limited liability company) of which more than 50% of the total voting power of Voting Stock is at the time owned or controlled, directly or indirectly, by that Person or one or more of the other Subsidiaries of that Person (or a combination thereof); and

(2) any partnership (whether general or limited) or limited liability company (a) the sole general partner or the managing general partner or managing member of which is such Person or a Subsidiary of such Person, or (b) if there are more than a single general partner or member, either (x) the only general partners or managing members of which are such Person or one or more Subsidiaries of such Person (or any combination thereof) or (y) such Person owns or controls, directly or indirectly, a majority of the outstanding general partner interests, member interests or other Voting Stock of such partnership or limited liability company, respectively.

“Subsidiary Guarantee” means any guarantee by a Subsidiary Guarantor of COO’s Obligations under the Indenture and on the Notes.

(1) the Restricted Subsidiaries executing the Indenture as initial Subsidiary Guarantors; and

(2) any other Restricted Subsidiary of COO that becomes a Subsidiary Guarantor in accordance with the provisions of the Indenture;

in each case, until released in accordance with the Indenture, and their respective successors and assigns.

“Unrestricted Subsidiary” means any Subsidiary of COO that is designated by the Board of COO as an Unrestricted Subsidiary pursuant to a Board Resolution, but only to the extent that such Subsidiary:

(2) is a Person with respect to which neither COO nor any of its Restricted Subsidiaries has any direct or indirect obligation (a) to subscribe for additional Equity Interests or (b) to maintain or preserve such Person’s financial condition or to cause such Person to achieve any specified levels of operating results;

(3) does not guarantee or otherwise directly or indirectly provide credit support for any Indebtedness of COO or any of its Restricted Subsidiaries; and

(4) is not party to any agreement, contract, arrangement or understanding with COO or any Restricted Subsidiary that is not in compliance with the covenant described above under “—Certain Covenants—Affiliate Transactions.”

Any Subsidiary of an Unrestricted Subsidiary shall also be an Unrestricted Subsidiary.

Any designation of a Subsidiary of COO as an Unrestricted Subsidiary will be evidenced to the trustee by filing with the trustee a Board Resolution giving effect to such designation and an officers’ certificate certifying that such designation complied with the preceding conditions and was permitted by the covenant described above under “—Certain Covenants—Restricted Payments.” If, at any time, any Unrestricted Subsidiary would fail to meet the preceding requirements as an Unrestricted Subsidiary, it will thereafter cease to be an Unrestricted Subsidiary for purposes of the Indenture and any Indebtedness of such Subsidiary will be deemed to be incurred by a Restricted Subsidiary of COO as of such date, any Liens on the assets of such Subsidiary shall be deemed to be incurred by a Restricted Subsidiary of COO at such time and any Investments held by such Subsidiary shall be deemed to be made by a Restricted Subsidiary of COO at such time and, if such Indebtedness is not permitted to be incurred as of such date under the covenant described under “—Certain Covenants—Incurrence of Indebtedness and Issuance of Preferred Stock,” such Lien is not permitted to be incurred as of such date under the covenant described above under “—Certain Covenants—Liens” or such Investment is not permitted to be made as of such date under the covenant described above under “—Certain Covenants—Restricted Payments,” COO will be in default of such covenant.

“Voting Stock” of any Person as of any date means the Capital Stock of such Person that is at the time entitled (without regard to the occurrence of any contingency) to vote in the election of the Board of such Person.

“Weighted Average Life to Maturity” means, when applied to any Indebtedness at any date, the number of years obtained by dividing:

(1) the sum of the products obtained by multiplying (a) the amount of each then remaining installment, sinking fund, serial maturity or other required payments of principal, including payment at final maturity, in respect of the Indebtedness, by (b) the number of years (calculated to the nearest one-twelfth) that will elapse between such date and the making of such payment; by

Except as set forth below, the exchange notes will be issued in registered, global form (“Global Notes”). The Global Notes will be deposited upon issuance with the Trustee as custodian for The Depository Trust Company (“DTC”), in New York, New York, and registered in the name of DTC or its nominee, in each case, for credit to an account of a direct or indirect participant in DTC as described below.

Except as set forth below, the Global Notes may be transferred, in whole and not in part, only to another nominee of DTC or to a successor of DTC or its nominee. Beneficial interests in the Global Notes may not be exchanged for definitive notes in registered certificated form (“Certificated Notes”) except in the limited circumstances described below. See “—Certificated Securities.” Except in the limited circumstances described below, owners of beneficial interests in the Global Notes will not be entitled to receive physical delivery of such notes in certificated form.

Transfers of beneficial interests in the Global Notes will be subject to the applicable rules and procedures of DTC and its direct or indirect participants (including, if applicable, those of Euroclear System (“Euroclear”) and Clearstream Banking, S.A. (“Clearstream”)), which may change from time to time.

The following description of the operations and procedures of DTC, Euroclear and Clearstream are provided solely as a matter of convenience. These operations and procedures are solely within the control of the respective settlement systems and are subject to changes by them without notice. We take no responsibility for these operations and procedures and urge investors to contact the system or their participants directly to discuss these matters.

DTC has advised us that DTC is a limited-purpose trust company created to hold securities for its participating organizations (collectively, the “Participants”) and to facilitate the clearance and settlement of transactions in those securities between the Participants through electronic book-entry changes in accounts of Participants. The Participants include securities brokers and dealers (including the initial purchasers), banks, trust companies, clearing corporations and certain other organizations. Access to DTC’s system is also available to other entities such as banks, brokers, dealers and trust companies that clear through or maintain a custodial relationship with a Participant, either directly or indirectly (collectively, the “Indirect Participants”). Persons who are not Participants may beneficially own securities held by or on behalf of DTC only through the Participants or the Indirect Participants. The ownership interests in, and transfers of ownership interests in, each security held by or on behalf of DTC are recorded on the records of the Participants and Indirect Participants.

Investors in the Global Notes who are Participants may hold their interests therein directly through DTC. Investors in the Global Notes who are not Participants may hold their interests therein indirectly through organizations (including Euroclear and Clearstream) which are Participants. Euroclear and Clearstream will hold interests in the Global Notes on behalf of their participants through customers’ securities accounts in their respective names on the books of their respective depositories, which are Euroclear Bank S.A./N.V., as operator of Euroclear, and Citibank, N.A., as operator of Clearstream. All interests in a Global Note, including those held through Euroclear or Clearstream, may be subject to the procedures and requirements of DTC. Those interests held through Euroclear or Clearstream may also be subject to the procedures and requirements of such systems. The laws of some states require that certain Persons take physical delivery in definitive form of securities that they own. Consequently, the ability to transfer beneficial interests in a Global Note to such Persons will be limited to that extent. Because DTC can act only on behalf of the Participants, which in turn act on behalf of the Indirect Participants, the ability of a Person having beneficial interests in a Global Note to pledge such interests to Persons that do not participate in the DTC system, or otherwise take actions in respect of such interests, may be affected by the lack of a physical certificate evidencing such interests.

Except as described below, owners of interests in the Global Notes will not have notes registered in their names, will not receive physical delivery of notes in certificated form and will not be considered the registered owners or “holders” thereof under the indenture for any purpose.

Payments in respect of the principal of, and interest and premium, if any, on, a Global Note registered in the name of DTC or its nominee will be payable to DTC in its capacity as the registered holder under the indenture. Under the terms of the indenture, the issuers and the trustee will treat the Persons in whose names the notes, including the Global Notes, are registered as the owners of the notes for the purpose of receiving payments and for all other purposes. Consequently, none of the issuers, the trustee or any agent of the issuers or the trustee has or will have any responsibility or liability for:

DTC has advised us that its current practice, upon receipt of any payment in respect of securities such as the exchange notes (including principal and interest), is to credit the accounts of the relevant Participants with the payment on the payment date unless DTC has reason to believe that it will not receive payment on such payment date. Each relevant Participant is credited with an amount proportionate to its beneficial ownership of an interest in the principal amount of the relevant security as shown on the records of DTC. Payments by the Participants and the Indirect Participants to the beneficial owners of notes will be governed by standing instructions and customary practices and will be the responsibility of the Participants or the Indirect Participants and will not be the responsibility of DTC, the trustee or the issuers. Neither we nor the trustee will be liable for any delay by DTC or any of the Participants or the Indirect Participants in identifying the beneficial owners of the notes, and the issuers and the trustee may conclusively rely on and will be protected in relying on instructions from DTC or its nominee for all purposes.

Transfers between the Participants will be effected in accordance with DTC’s procedures, and will be settled in same-day funds, and transfers between participants in Euroclear and Clearstream will be effected in accordance with their respective rules and operating procedures.

Subject to compliance with the transfer restrictions applicable to the exchange notes described herein, cross-market transfers between the Participants, on the one hand, and Euroclear or Clearstream participants, on the other hand, will be effected through DTC in accordance with DTC’s rules on behalf of Euroclear or Clearstream, as the case may be, by their respective depositaries; however, such cross-market transactions will require delivery of instructions to Euroclear or Clearstream, as the case may be, by the counterparty in such system in accordance with the rules and procedures and within the established deadlines (Brussels time) of such system. Euroclear or Clearstream, as the case may be, will, if the transaction meets its settlement requirements, deliver instructions to its respective depositary to take action to effect final settlement on its behalf by delivering or receiving interests in the relevant Global Note in DTC, and making or receiving payment in accordance with normal procedures for same-day funds settlement applicable to DTC. Euroclear participants and Clearstream participants may not deliver instructions directly to the depositories for Euroclear or Clearstream.

DTC has advised us that it will take any action permitted to be taken by a holder of exchange notes only at the direction of one or more Participants to whose account DTC has credited the interests in the Global Notes and only in respect of such portion of the aggregate principal amount of the notes as to which such Participant or Participants has or have given such direction. However, if there is an event of default with respect to the notes (as defined in the indenture), DTC reserves the right to exchange the Global Notes in certificated form, and to distribute such notes to its Participants.

Although DTC, Euroclear and Clearstream have agreed to the foregoing procedures to facilitate transfers of interests in the Global Notes among participants in DTC, Euroclear and Clearstream, they are under no obligation to perform or to continue to perform such procedures, and may discontinue such procedures at any time without notice. None of the issuers, the trustee or any of their respective agents will have any responsibility for the performance by DTC, Euroclear or Clearstream or their respective participants or indirect participants of their respective obligations under the rules and procedures governing their operations.

Certificated securities shall be issued in exchange for beneficial interests in the Global Notes (i) if requested by a holder of such interests or (ii) if DTC is at any time unwilling or unable to continue as a depositary for the Global Notes and a successor depositary is not appointed by the Company within 90 days.

The following discussion summarizes only the U.S. federal income tax considerations relating to the exchange of original notes for exchange notes pursuant to the exchange offer. This discussion is based upon the Internal Revenue Code of 1986, as amended (the “Code”), Treasury Regulations promulgated under the Code, court decisions, published positions of the Internal Revenue Service (the “IRS”) and other applicable authorities, all as in effect on the date of this document and all of which are subject to change or differing interpretations, possibly with retroactive effect. This discussion is limited to holders of exchange notes received pursuant to the exchange offer in exchange for original notes purchased for cash at the original issue for the original issue price who hold the exchange notes as “capital assets” within the meaning of Section 1221 of the Code. This summary does not address all of the U.S. federal income tax consequences that may be applicable to particular holders, including dealers in securities, financial institutions, insurance companies and tax-exempt organizations.

This discussion also does not address foreign, state, local, estate or gift tax laws that may be applicable to a particular holder. No ruling has been or is expected to be obtained from the IRS regarding the U.S. federal income tax consequences relating to the exchange of original notes for exchange notes pursuant to the exchange offer. As a result, no assurance can be given that the IRS will not assert, or that a court will not sustain, a position contrary to the conclusions set forth below.

HOLDERS ARE URGED TO CONSULT THEIR OWN TAX ADVISOR AS TO THE PARTICULAR TAX CONSEQUENCES OF PARTICIPATING IN THE EXCHANGE OFFER, INCLUDING THE APPLICATION OF THE FEDERAL ESTATE OR GIFT TAX RULES, THE LAWS OF ANY STATE, LOCAL, FOREIGN OR OTHER TAXING JURISDICTION OR TAX TREATY, AND ANY CHANGES OR PROPOSED CHANGES IN APPLICABLE TAX LAWS OR INTERPRETATIONS THEREOF.

The exchange of original notes for exchange notes pursuant to the exchange offer will not be treated as a taxable exchange for U.S. federal income tax purposes. Consequently, for U.S. federal income tax purposes:

Each broker-dealer that receives exchange notes pursuant to the exchange offer must acknowledge that it will deliver a prospectus in connection with any resale of exchange notes. This prospectus, as it may be amended or supplemented from time to time, may be used by a broker-dealer in connection with resales of exchange notes received in exchange for original notes where such original notes were acquired as a result of market-making activities or other trading activities. We have agreed in the registration rights agreement to make this prospectus available to such broker-dealers upon reasonable request for the period required by the Securities Act. In addition, until September 11, 2013 (90 days after the date of this prospectus), all dealers effecting transactions in the exchange notes may be required to deliver a prospectus.

We will not receive any proceeds from the exchange of original notes for exchange notes or from any sale of exchange notes by broker-dealers. Exchange notes received by broker-dealers for their own account pursuant to the exchange offer may be sold from time to time in one or more transactions:

Any such resale may be made directly to purchasers or to or through brokers or dealers who may receive compensation in the form of commissions or concessions from any such broker-dealer or the purchasers of any such exchange notes.

Any broker-dealer that resells exchange notes received pursuant to the exchange offer and any broker or dealer that participates in a distribution of such exchange notes may be deemed to be an “underwriter” within the meaning of the Securities Act and any profit on any such resale of exchange notes and any commissions or concessions received by any such persons may be deemed to be underwriting compensation under the Securities Act. The letter of transmittal states that, by acknowledging that it will deliver a prospectus and by delivering a prospectus, a broker-dealer will not be deemed to admit that it is an “underwriter” within the meaning of the Securities Act. The letter of transmittal also states that any holder participating in this exchange offer will have no arrangements or understandings with any person to participate in the distribution of the original notes or the exchange notes within the meaning of the Securities Act. In addition, holders of original notes that tender their original notes in exchange for exchange notes must make the representations set forth in this prospectus under the heading “The Exchange Offer—Conditions to the Exchange Offer” and in the related letter of transmittal.

We have agreed to pay all expenses incident to the exchange offer, including all registration and filing fees and expenses (including filings made by any holder of original notes with the Financial Industry Regulatory Authority (FINRA), and, if applicable, the fees and expenses of any “qualified independent underwriter” and its counsel that may be required by the rules and regulations of FINRA), all fees and expenses of compliance with federal securities and state securities or blue sky laws, all expenses of printing, all fees and disbursements of our legal counsel, and, under certain circumstances, legal counsel for holders of original notes, and all fees and disbursements of our independent certified public accountants, and we will indemnify the holders of the original notes (including any broker-dealers) against certain liabilities, including liabilities under the Securities Act.

The validity of the exchange notes and the guarantees will be passed upon for us by Bracewell & Giuliani LLP, Houston, Texas. Certain legal matters relating to Oklahoma law will be passed upon for us by Commercial Law Group, P.C., Oklahoma City, Oklahoma.

The consolidated financial statements of Chesapeake Oilfield Operating, L.L.C. as of December 31, 2012 and 2011 and for each of the three years in the period ended December 31, 2012, included in this prospectus, have been so included in reliance on the report of PricewaterhouseCoopers LLP, an independent registered public accounting firm, given on the authority of said firm as experts in auditing and accounting.

The audited consolidated financial statements of Bronco Drilling Company, Inc. and subsidiaries as of December 31, 2010 and 2009, and for each of the three years ended December 31, 2010, included in this prospectus and elsewhere in the registration statement have been so included in reliance upon the report of Grant Thornton LLP, independent registered public accountants, upon authority of said firm as experts in accounting and auditing in giving said report.

We have filed with the SEC a registration statement on Form S-4, including all required exhibits and schedules, under the Securities Act to register the offer and exchange of the exchange notes for the original notes. This prospectus does not contain all of the information set forth in the registration statement and the exhibits and schedules thereto. For further information, we refer you to the registration statement and the exhibits and schedules filed therewith.

Statements contained in this prospectus as to the contents of any contract, agreement or any other document are summaries of the material terms of such contract, agreement or other document. With respect to each of these contracts, agreements or other documents filed as an exhibit to the registration statement, reference is made to the exhibits to the registration statement for a more complete description thereof. A copy of the registration statement, and the exhibits and schedules thereto, may be inspected without charge at the public reference facilities maintained by the SEC at 100 F Street NE, Washington, D.C. 20549. Copies of these materials may be obtained, upon payment of a duplicating fee, from the Public Reference Section of the SEC at 100 F Street NE, Washington, D.C. 20549. Please call the SEC at 1-800-SEC-0330 for further information on the operation of the public reference facility. The SEC maintains a website that contains reports, proxy and information statements and other information regarding registrants that file electronically with the SEC. The address of the SEC’s website is http://www.sec.gov.

Following the completion of this exchange offer, Chesapeake Oilfield Operating, L.L.C. will file annual, quarterly and current reports and other information with the SEC. Our website is located at www.chesapeakeoilfieldservices.com, and we expect to make our periodic reports and other information filed with or furnished to the SEC available, free of charge, through our website, as soon as reasonably practicable after those reports and other information are electronically filed with or furnished to the SEC. Information on our website or any other website is not incorporated by reference into this prospectus and does not constitute a part of this prospectus. You may request a copy of our filings, at no cost, by writing or telephoning us at the following address and telephone number:

In our opinion, the accompanying consolidated balance sheets and the related consolidated statements of operations, of changes in equity and of cash flows present fairly, in all material respects, the financial position of Chesapeake Oilfield Operating, L.L.C. (the “Company”) and its subsidiaries at December 31, 2012 and 2011, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2012 in conformity with accounting principles generally accepted in the United States of America. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits of these statements in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

As discussed in Notes 13 and 14 to the accompanying consolidated financial statements, the Company earned the majority of its revenues and has other significant transactions with affiliated entities.

The accompanying notes are an integral part of these consolidated financial statements.

Chesapeake Oilfield Operating, L.L.C. (“COO,” “we,” “us,” “our” or “ours”) is an Oklahoma limited liability company formed in September 2011 to own and operate the oilfield services companies of Chesapeake Energy Corporation (“Chesapeake”). We conduct operations through the following wholly owned and consolidated subsidiaries: Nomac Drilling, L.L.C. (“Nomac”), Performance Technologies, L.L.C., PTL Prop Solutions, L.L.C., Thunder Oilfield Services, L.L.C., Compass Manufacturing, L.L.C., Hodges Trucking Company, L.L.C. (“Hodges”), Oilfield Trucking Solutions, L.L.C. (“OTS”), Great Plains Oilfield Rental, L.L.C., Keystone Rock & Excavation, L.L.C., Mid-States Oilfield Supply LLC, Western Wisconsin Sand Company, LLC (“WWS”) and Nomac Services, L.L.C. (“Nomac Services”).

The accompanying consolidated financial statements and related notes include the accounts of COO and its subsidiaries, all of which were wholly owned as of and after October 25, 2011, and prior to that date include the assets, liabilities, results of operations and cash flows of Chesapeake’s oilfield service operations on a carve out basis. Chesapeake transferred those assets to COO on October 25, 2011 and the transferred assets and liabilities were carried forward to COO and are presented for all periods at their historical costs. COO’s accounting and financial reporting policies conform to accounting principles and practices generally accepted in the United States of America (“GAAP”). All significant intercompany accounts and transactions within COO have been eliminated.

The capital intensive nature of the oilfield services business in conjunction with our rapid growth required Chesapeake to provide regular capital infusions to fund our activities prior to 2012. For purposes of these financial statements, management has allocated these advances to affiliate debt based on the portion of Chesapeake’s consolidated debt estimated to be attributable to our operations. Interest expense was assumed to be paid to Chesapeake through additional borrowings of affiliate debt prior to October 25, 2011. On October 28, 2011, we issued $650.0 million of 6.625% Senior Notes due 2019 (the “2019 Senior Notes” or the “Notes”). We used the net proceeds of $637.0 million from the 2019 Senior Notes issuance to pay down a portion of our affiliate debt with Chesapeake. On November 3, 2011, we entered into a five-year senior secured revolving bank credit facility (the “Credit Facility”) with total commitments of $500.0 million. Prior to the completion of the 2019 Senior Notes issuance and the Credit Facility, certain subsidiaries of COO were guarantors of substantially all of Chesapeake’s debt. In connection with our issuance of the 2019 Senior Notes and our entry into the Credit Facility, the subsidiaries ceased to be guarantors with respect to the debt of Chesapeake and became guarantors of the 2019 Senior Notes and the Credit Facility.

Chesapeake provides cash management services to COO through a centralized treasury system. Prior to October 25, 2011, all intercompany charges and cost allocations covered by the centralized treasury system were deemed to have been paid to or received from Chesapeake in cash during the period in which the respective transactions were recorded in the financial statements. All intercompany charges and cost allocations were and will continue to be cash settled on and after October 25, 2011. Transactions between COO and Chesapeake have been identified in the financial statements as transactions between affiliates (see Notes 13 and 14).

The accompanying consolidated financial statements include 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. These charges from Chesapeake were $49.4 million, $33.7 million and $23.9 million for the years ended December 31, 2012, 2011 and 2010, respectively. Management believes that the allocated charges are representative of the costs and expenses incurred by Chesapeake for COO. See Note 14 for discussion of the methods of allocation.

We provide a wide range of wellsite services, including drilling, hydraulic fracturing, oilfield rentals, rig relocation, fluid transportation and disposal, and other ancillary oilfield services. In addition, we manufacture natural gas compressors for a wholly owned subsidiary of Chesapeake. We conduct our operations in Kansas, Louisiana, Montana, North Dakota, Ohio, Oklahoma, Pennsylvania, Texas, West Virginia, Wisconsin and Wyoming. As of December 31, 2012, our primary owned operating assets consisted of 51 drilling rigs, seven hydraulic fracturing fleets, 278 rig relocation trucks, 66 cranes and forklifts and 250 trucks for fluid hauling and disposal. Additionally, we had 68 rigs leased under contracts from an affiliate at December 31, 2012 (see Note 7). Our reportable business segments are drilling, hydraulic fracturing, oilfield rentals, oilfield trucking and other operations (see Note 15).

The preparation of consolidated financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the balance sheet date and the reported amounts of revenues and expenses during the reporting periods. Although management believes these estimates are reasonable, actual results could differ from those estimates. Areas where critical accounting estimates are made by management include:

Historically, we have provided substantially all of our oilfield services to Chesapeake. For the years ended December 31, 2012, 2011 and 2010, Chesapeake accounted for approximately 94%, 94% and 96%, respectively, of our revenues. Approximately 70% of Chesapeake’s estimated proved reserves volumes as of December 31, 2012 were natural gas and 80% of Chesapeake’s 2012 oil and natural gas sales volumes were natural gas. Sustained low natural gas prices, 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 Credit Facility and further limit our ability to fund our planned capital expenditures.

Trade accounts receivable are recorded at the invoice amount and do not bear interest. The majority of our receivables, 93% and 85% at December 31, 2012 and 2011, respectively, are with Chesapeake and its subsidiaries. The allowance for doubtful accounts is our best estimate for losses that may occur resulting from disputed amounts with our unaffiliated third-party customers and their inability to pay amounts owed. We determine the allowance based on historical write-off experience and information about specific customers. During 2012, 2011 and 2010, we recognized $0.5 million, $0 and $0, respectively, of bad debt expense related to potentially uncollectible receivables.

We value inventory at the lower of cost or market using the average cost method. Average cost is derived from third-party invoices and production cost. Production cost includes material, labor and manufacturing overhead. Inventory primarily consists of proppants and chemicals used in our hydraulic fracturing operations and components used in our compressor manufacturing business. A summary of our inventory is as follows:

Property and equipment are carried at cost less accumulated depreciation. Depreciation of assets is based on estimates, assumptions and judgments relative to useful lives and salvage values. Upon the disposition of an asset, we eliminate the cost and related accumulated depreciation and include any resulting gain or loss in operating expenses in the consolidated statements of operations. We recorded net (losses) gains on sales of property and equipment of ($2.0) million, $3.6 million and $0.9 million for the years ended December 31, 2012, 2011 and 2010, respectively. Expenditures for maintenance and repairs that do not add capacity or extend the useful life of an asset are expensed as incurred.

Depreciation is calculated using the straight-line method based on 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.

Depreciation expense on property and equipment for the years ended December 31, 2012, 2011 and 2010 was $227.2 million, $173.2 million and $102.7 million, respectively. Included in property and equipment are $178.7 million and $129.8 million at December 31, 2012 and 2011, respectively, of assets that are being constructed or have not been put into service and therefore are not subject to depreciation.

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 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 future undiscounted cash flows of the asset. If an impairment has occurred, we recognize a loss for the difference between the carrying amount and the fair 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.

Investments in securities are accounted for under the equity method in circumstances where we have the ability to exercise significant influence over the operating and investing policies of the investee but do not have control. Under the equity method, we recognize our share of the investee’s earnings in our consolidated statements of operations. We consolidate all subsidiaries in which we hold a controlling interest.

We evaluate our investments for impairment and recognize a charge to earnings when any identified impairment is determined to be other than temporary. See Note 10 for further discussion of investments.

An entity is referred to as a variable interest entity (“VIE”) pursuant to accounting guidance for consolidation if it possesses one of the following criteria: (i) it is thinly capitalized, (ii) the residual equity holders do not control the entity, (iii) the equity holders are shielded from the economic losses, (iv) the equity holders do not participate fully in the entity’s residual economics, or (v) the entity was established with non-substantive voting interests. We consolidate a VIE when we have both the power to direct the activities that most significantly impact the activities of the VIE and the right to receive benefits or the obligation to absorb losses of the entity that could be potentially significant to the VIE. We do not consolidate VIEs when we are not the primary beneficiary. In order to determine whether we have a variable interest in a VIE, we perform a qualitative analysis of the entity’s design, organizational structure, primary decision makers and relevant agreements. We continually monitor VIEs to determine if any events have occurred that could cause the primary beneficiary to change. See Note 11 for further discussion.

Goodwill represents the cost in excess of fair value of the net assets of businesses acquired. In 2011, we recorded goodwill in the amounts of $27.4 million and $15.1 million related to our acquisitions of Bronco Drilling Company, Inc. (“Bronco”) and Horizon Oilfield Services, L.L.C. (“Horizon”), respectively (See Note 4). Goodwill is 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 for impairment annually on October 1 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 of. Under GAAP, we have the option to first assess qualitative factors to determine whether the existence of events or circumstances leads to a determination that it is more likely than not that the fair value of one of our reporting units is greater than its carrying amount. If, after assessing the totality of events or circumstances, we determine it is more likely than not that the fair value of a reporting unit is greater than its carrying amount, then there is no need to perform any further testing. However, if we conclude otherwise, 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 goodwill over its implied fair value. We have the option to bypass the qualitative assessment for any reporting unit in any period and proceed directly to performing the first step of the two-step goodwill impairment test.

Our definite-lived intangible assets, consisting of customer relationships and a trade name, are amortized, using the straight-line method. A summary of these assets and their useful lives is as follows:

Amortization expense was $3.9 million, $2.6 million and $0.6 million for the years ended December 31, 2012, 2011 and 2010, respectively. Future estimated amortization expense is presented below.

Legal fees and other costs incurred in obtaining financing are amortized over the term of the debt using a method that approximates the effective interest method. Gross deferred financing costs were $20.2 million at December 31, 2012 related to our Credit Facility and 2019 Senior Notes. Prior to 2011, we had no deferred financing costs. Amortization expense related to deferred financing costs was $2.9 million and $0.5 million for the years ended December 31, 2012 and 2011, respectively, and is included in interest expense in the consolidated statements of operations.

Included in accounts payable at December 31, 2012 and 2011 are liabilities of $15.0 million and $13.4 million, respectively, representing the amount by which checks issued, but not yet presented to our banks for collection, exceeded balances in applicable bank accounts, considering the legal right of offset.

Oilfield Rentals. We rent many types of oilfield equipment including drill pipe, drill collars, tubing, blowout preventers, frac tanks, mud tanks and environmental containment. We also provide air drilling, flowback services and services associated with the transfer of water to the wellsite for well completions. We price our rentals and services by the day or hour based on the type of equipment being rented and the service job 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 handling services. Our trucks move drilling rigs, crude oil, other fluids and construction materials to and from the wellsites and also transport produced water from the wellsites. 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 and third parties. We price our compression units based on certain specifications such as horsepower, stages and additional options. We recognize revenue upon completion and transfer of ownership of the natural gas compression unit.

We estimate our accruals related to litigation based on the facts and circumstances specific to the litigation and our past experience with similar claims. We estimate our liability related to pending litigation when we believe the amount or a range of the loss can be reasonably estimated. We record our best estimate of a loss when the loss is considered probable. When a loss is probable and there is a range of estimated loss with no best estimate in the range, we record the minimum estimated liability related to a lawsuit or claim. As additional information becomes available, we assess the potential liability related to our pending litigation and claims and revise our estimates accordingly.

Our operations involve the storage, handling, transport and disposal of bulk waste materials, some of which contain oil, contaminants and regulated substances. These operations are subject to various federal, state and local laws and regulations intended to protect the environment. Environmental expenditures are expensed or capitalized depending on their future economic benefit. Expenditures that relate to an existing condition caused by past operations and that have no future economic benefit are expensed. There were no amounts capitalized as of December 31, 2012 and 2011. We record liabilities on an undiscounted basis when remediation efforts are probable and the costs to conduct such remediation efforts can be reasonably estimated.

We lease drilling rigs, real property and rail cars through various leasing arrangements (see Note 7). When we enter into a leasing arrangement, we analyze the terms of the arrangement to determine its accounting treatment. As of December 31, 2012, all leases have been accounted for as operating leases.

We periodically incur costs to improve the assets that we lease under these arrangements. We record the improvement as a component of property and equipment and amortize the improvement over the shorter of the useful life of the improvement or the remaining lease term.

The benefit of an uncertain tax position taken or expected to be taken on an income tax return is recognized in the consolidated financial statements at the largest amount that is more likely than not to be sustained upon examination by the relevant taxing authority. Interest and penalties, if any, related to uncertain tax positions would be recorded in interest expense and other expense, respectively. There were no uncertain tax positions at December 31, 2012 and 2011.

Certain reclassifications have been made to the consolidated financial statements for 2011 and 2010 to conform to the presentation used for the 2012 consolidated financial statements. We have also revised the cash flow statement to correct the classification of deposits made for the purchase of property, plant and equipment in 2011 and 2010, which were previously reported as a use of operating cash flows instead of a use of investing cash flows, and to correct the classification of cash paid to acquire the remaining non-controlling interest in a subsidiary in 2011, which was previously reported as a use of investing cash flows instead of a use of financing cash flows. The effect of these revisions increased cash provided by operating activities by $17.5 million, increased cash used in investing activities by $14.3 million and decreased cash provided by financing activities by $3.1 million in 2011, and increased cash provided by operating activities by $3.4 million and increased cash used in investing activities by $3.4 million in 2010 as compared to amounts previously reported. These amounts are not considered material to the consolidated financial statements for 2011 and 2010.

During 2012, we sold 18 drilling rigs and ancillary equipment. The drilling rigs and equipment sold were not being utilized in our business and were sold as part of our broader strategy to divest non-essential drilling rigs. We received proceeds of $7.4 million, net of selling expenses, for the drilling rigs and related equipment and recorded a loss on sale of approximately $8.2 million. We recorded net gains on sales of other property and equipment of $6.2 million, $3.6 million and $0.9 million for the years ended December 31, 2012, 2011 and 2010, respectively.

During the year ended December 31, 2012, we identified certain drilling rigs and spare equipment to sell as part of our broader strategy to divest non-essential drilling rigs. We are required to present such assets at the lower of carrying amount or fair value less the anticipated costs to sell at the time they meet the criteria for held for sale accounting. We recorded impairment charges of $11.7 million during the year ended December 31, 2012 related to certain of these drilling rigs and spare equipment because their estimated fair values less costs to sell were lower than their carrying values. Estimated fair value for the drilling rigs and spare equipment was determined using recent sales transactions of comparable assets with similar specifications (Level 3). We had nine drilling rigs and ancillary equipment that we had not disposed of at year end with a net book value of approximately $26.5 million, which are included in property and equipment held for sale in our consolidated balance sheet as of December 31, 2012. The drilling rigs and spare equipment are reported under our drilling segment.

During the year ended December 31, 2012, we repurchased 25 leased drilling rigs for approximately $61.1 million (see Note 7). We recognized lease termination costs of approximately $24.9 million, which was the difference between the purchase price pursuant to the repurchase agreement and the estimated fair value of the drilling rigs. The lease termination costs are included in impairments and other on the consolidated statements of operations. Estimated fair value for the drilling rigs was determined using recent sales transactions of comparable assets with similar specifications (Level 3). As a result of these transactions, we realized deferred gains of approximately $2.3 million, recorded as a reduction in operating expense for the year ended December 31, 2012.

For our drilling segment, we perform an impairment evaluation and estimate future undiscounted cash flows for individual drilling rigs when impairment indicators are present. In connection with our estimates of future undiscounted cash flows, we identified four rigs during the year ended December 31, 2012 that we deemed to be impaired based on our assessment of future demand and the suitability of the identified rigs in light of this expected demand. We recorded impairment charges of $14.9 million during the year ended December 31, 2012 related to such drilling rigs as the difference between the carrying value of $32.4 million and an estimated fair value of $17.5 million. Estimated fair value for the drilling rigs was determined using recent sales transactions of comparable assets with similar specifications (Level 3).

The market approach was based on external industry data for similar equipment. The assumptions used in the impairment evaluation for long-lived assets are inherently uncertain and require management’s judgment. Continued lower natural gas prices or decreased oil prices or additional reductions in capital expenditures by Chesapeake and the potential impact of these factors on our utilization and dayrates could result in the recognition of future impairment charges on the same or additional rigs and other property and equipment if future cash flow estimates, based upon information then available to management, indicate that their carrying value may not be recoverable.

We also identified certain excess drill pipe, included in our oilfield rentals and drilling segments that had become obsolete due to Chesapeake’s transition to liquids-focused drilling and reduced natural gas drilling. The carrying value of the drill pipe was reduced to fair value. We recorded impairment charges of $7.5 million during the year ended December 31, 2012 related to such drill pipe as the difference between the carrying amount of $12.9 million and an estimated fair value of $5.4 million. We recorded additional impairments of $1.7 million, $2.7 million and $0.0 during the years ended December 31, 2012, 2011 and 2010, respectively, related to obsolescence.

On January 19, 2012, we entered into an agreement to acquire the assets of and 90.0% of the profit interests in WWS for $2.4 million. WWS’s assets consist of leases for mineral rights and one permit to excavate sand. We expect to build the infrastructure necessary to utilize the acquired leases and permit to excavate sand for our hydraulic fracturing operations. We accounted for this acquisition as an asset acquisition. Under the agreement, we could be required to make future additional payments to the sellers not to exceed $6.0 million to obtain the remaining 10.0% of the profit interests. These payments are contingent on the completion of certain operating targets, including the construction of new sand processing plants and those plants meeting certain production levels. No payments were required as of December 31, 2012.

On November 18, 2011, we entered into an agreement to acquire 100% of the membership interests in Horizon for $17.5 million. Horizon was merged into Nomac Services during 2011. Horizon provided field geology services, including mud logging, geosteering and geotechnical services in connection with oil and natural gas exploration and production activities. The assets acquired consisted primarily of field equipment, vehicles, trailers, accounts receivable and a highly technical workforce. We allocated the purchase price to property and equipment, accounts receivable and goodwill in the amounts of $1.4 million, $1.1 million and $15.0 million, respectively, based on their fair values at the date of acquisition. None of the goodwill is deductible for tax purposes. Goodwill is primarily attributable to operational and cost synergies expected to be realized from the acquisition by integrating Horizon’s assembled workforce. The goodwill was assigned to our drilling segment. See “Goodwill, Intangible Assets and Amortization” in Note 2 for further discussion of goodwill.

On June 6, 2011, we acquired Bronco for an aggregate cash purchase price of $339.2 million, or $11.00 per share of Bronco common stock. The following table summarizes the fair value of assets acquired and liabilities assumed:

We received carryover tax basis in Bronco’s assets and liabilities because the acquisition was not a taxable transaction under the Internal Revenue Code. Based upon the purchase price allocation, a step-up in basis related to the assets acquired from Bronco resulted in a net deferred tax liability of approximately $25.3 million. Prior to purchase price adjustments, we recorded goodwill of $52.1 million, which represents the amount of the consideration transferred in excess of the fair values assigned to the individual assets acquired and liabilities assumed. During the year ended December 31, 2011, we recorded approximately $24.7 million of purchase price adjustments largely related to a reduction in the deferred income tax liability assumed as part of the transaction and tax refunds received. Goodwill is primarily attributable to operational and cost synergies expected to be realized from the acquisition by integrating Bronco’s drilling rigs and assembled workforce. None of the goodwill is deductible for tax purposes. The goodwill was assigned to our drilling segment. We tested the goodwill for impairment as of October 1, 2012 and concluded that no impairment was necessary. We assigned $10.0 million of the purchase price to customer lists which are included in intangible assets on the balance sheet at December 31, 2012. Customer lists are being amortized under the straight-line method over three years.

The following table sets forth our unaudited pro forma revenues and net income (loss) giving effect to the Bronco acquisition as though it was effective January 1, 2010. Pro forma adjustments primarily relate to additional depreciation, amortization and interest costs. The information reflects our historical data and historical data from the acquired business for the periods indicated. The pro forma data may not be indicative of the results we would have achieved had the acquisition been completed on the date assumed, or that we may achieve in the future.

On August 31, 2010, we completed the acquisition of an additional 12% of the preferred stock of Resource Energy Services Corporation (“Rensco”), increasing our interest from 46% to 58%, and providing us with control of Rensco. Rensco was merged into Nomac Services during 2011. As a result of obtaining control, we began to consolidate Rensco’s financial results with ours and reflect a noncontrolling interest as a separate component of equity on the consolidated balance sheet. In 2011, we acquired the remaining 42% of the preferred stock of Rensco for $3.1 million, thereby eliminating such noncontrolling interest. The difference between the consideration paid for the remaining 42% and the carrying value attributed to the noncontrolling interest is reflected in owners’ equity. Rensco provided directional drilling services and downhole tools and equipment in connection with oil and natural gas exploration and production activities. Prior to August 31, 2010, we accounted for our 46% interest in Rensco as an equity method investment.

On October 28, 2011, we issued our 2019 Senior Notes in a private placement. We incurred $14.8 million in financing costs related to the Notes issuance which have been deferred and are being amortized over the life of the 2019 Senior Notes. We used the net proceeds of $637.0 million from the 2019 Senior Notes issuance to pay down a portion of our affiliate debt with Chesapeake. The 2019 Senior Notes will mature on November 15, 2019 and interest is payable semi-annually on each of May 15 and November 15, which began on May 15, 2012. COO and Chesapeake Oilfield Finance, Inc., our wholly owned subsidiary, are the co-issuers of the 2019 Senior Notes.

We may redeem up to 35% of the 2019 Senior Notes with proceeds of certain equity offerings at a redemption price of 106.625% of the principal amount plus accrued and unpaid interest prior to November 15, 2014. Prior to November 15, 2015, but after November 15, 2014, we may redeem some or all of the 2019 Senior Notes at a price equal to 100% of the principal amount plus a make-whole premium determined pursuant to a formula set forth in the Indenture governing the 2019 Senior Notes, plus accrued and unpaid interest. On and after November 15, 2015, we may redeem all or part of the 2019 Senior Notes at the following prices (as a percentage of principal), plus accrued and unpaid interest, if redeemed during the 12-month period beginning on November 15 of the years indicated below:

subsidiaries to pay dividends, make intercompany loans or transfer assets to us; (7) effect a merger, consolidation or sale of all or substantially all of our assets; (8) enter into transactions with affiliates; and (9) designate subsidiaries as unrestricted subsidiaries. The 2019 Senior Notes also have cross default provisions that apply to other indebtedness COO or any of its guarantor subsidiaries may have from time to time with an outstanding principal amount of $50.0 million or more. If the 2019 Senior Notes achieve an investment grade rating by either of Moody’s Investors Service, Inc. (“Moody’s”) or Standard & Poor’s Rating Services (“S&P”), our obligation to comply with certain of these covenants will be suspended, and if the Notes achieve an investment grade rating from both of Moody’s and S&P, then such covenants will terminate.

Under a registration rights agreement, we agreed to file a registration statement within 365 days after the closing of the Notes offering enabling holders of the Notes to exchange the privately placed Notes for publicly registered exchange notes with substantially the same terms. We are required to use our commercially reasonable best efforts to cause the registration statement to become effective as soon as practicable after filing and to consummate the exchange offer on the earliest practicable date after the registration statement has become effective, but in no event later than 60 days after the date the registration statement has become effective. We also agreed to make additional interest payments, up to a maximum of 1.0% per annum, to holders of the Notes if we do not comply with our obligations under the registration rights agreement. We did not file a registration statement within 365 days after the closing of the Notes offering and, as of December 31, 2012, had accrued approximately $0.9 million of additional expense we expect to incur related to this delay. The Notes are guaranteed by all of our existing subsidiaries, other than certain immaterial subsidiaries.

On November 3, 2011, we entered into our $500.0 million Credit Facility. We incurred $5.4 million in financing costs related to entering into the Credit Facility which have been deferred and are being amortized over the life of the Credit Facility. The borrowing capacity of the Credit Facility may be increased to $900.0 million at our option, subject to compliance with the restrictive covenants in the Credit Facility and in the indenture governing our 2019 Senior Notes, as well as lender approval. The maximum amount that we may borrow under the Credit Facility may be subject to limitations due to certain covenants contained in the Credit Facility. As of December 31, 2012, the Credit Facility was not subject to any such limitations. The Credit Facility is used to fund capital expenditures and for general corporate purposes associated with our operations. Borrowings under the Credit Facility are secured by liens on our equity interests and the equity interests of our current and future guarantor subsidiaries and all of our guarantor subsidiaries’ assets, including real and personal property, and bear interest at our option at either (i) 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 (ii) 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. The unused portion of the Credit Facility is subject to a commitment fee that varies from 0.375% to 0.50% per annum, according to our leverage ratio. We recorded commitment fee expense of $1.4 million and $0.4 million for the years ended December 31, 2012 and 2011, respectively. Interest is payable quarterly or, if LIBOR applies, it may be payable at more frequent intervals. COO is the borrower under the Credit Facility.

The Credit Facility contains various covenants and restrictive provisions which limit our and our subsidiaries’ ability to incur additional indebtedness, make investments or loans and create liens. The Credit Facility requires maintenance of a leverage ratio, a senior secured leverage ratio and a fixed charge coverage ratio, in each case as defined in the Credit Facility agreement. We were in compliance with these covenants as of December 31, 2012. If we or our subsidiaries should fail to perform our obligations under these and other covenants, the Credit Facility could be terminated and any outstanding borrowings under the Credit Facility could be declared immediately due and payable. Such acceleration, if involving a principal amount of $50.0 million or more, would constitute an event of default under our 2019 Senior Notes indenture, which could in turn result in the acceleration of the senior note indebtedness. The Credit Facility also contains cross default provisions that apply to other indebtedness, including our 2019 Senior Notes, that we and our subsidiaries may have from time to time with an outstanding principal amount in excess of $15.0 million.

No scheduled principal payments are required on any of our long-term debt until November 2016, when our Credit Facility becomes due.

On October 28, 2011, we issued our 2019 Senior Notes in a private placement and used the net proceeds of $637.0 million to reduce our affiliate debt with Chesapeake. Interest expense charged to us of $38.2 million and $39.3 million for the years ended December 31, 2011 and 2010, respectively, was based on Chesapeake’s average borrowing rate. The average outstanding affiliate debt was $317.5 million and $567.1 million for the years ended December 31, 2011 and 2010, respectively.

On December 15, 2010, in connection with our acquisition of all the membership interests in Forrest Rig Company, L.L.C. and Forrest Top Drive, L.L.C. (collectively “Forrest”), we entered into a $49.5 million promissory note payable. The promissory note had a stated annual interest rate of 6.0%. We made principal and interest payments monthly in the amount of approximately $4.3 million until November 2, 2011, when the remaining obligation was repaid in its entirety.

Other current and long-term liabilities as of December 31, 2012 and 2011 are detailed below:

In a series of transactions beginning in 2006, we sold 68 drilling rigs (net of 26 repurchased rigs) and related equipment and entered into master lease agreements under which we agreed to lease the rigs from the buyers for initial terms ranging from five to ten years. These transactions were recorded as sales and operating leasebacks and any related net gains are amortized to operating expense over the lease term. The deferred gains, net of fees, are included in accrued liabilities and other liabilities on our consolidated balance sheets. We amortized $8.8 million, $6.3 million and $5.7 million to operating expense related to the deferred gains for the years ended December 31, 2012, 2011 and 2010, respectively.

As of December 31, 2012, we were a party to six lease agreements with various third parties to lease rail cars for initial terms of one to seven years. Additional rental payments are required for the use of rail cars in excess of the allowable mileage stated in the respective agreements. These leases are being accounted for as operating leases.

Rent expense for rigs, real property and rail cars for the years ended December 31, 2012, 2011 and 2010 was $118.8 million, $107.1 million and $94.7 million, respectively, and was included in operating costs in our consolidated statements of operations.

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

Much of the equipment we purchase requires long production lead times. As a result, we usually have outstanding orders and commitments for such equipment. As of December 31, 2012, we had $118.2 million of purchase obligations related to future capital expenditures primarily for drilling rigs and related equipment and hydraulic fracturing equipment that we expect to incur in 2013.

On October 7, 2011, we entered into an agreement to acquire 49% of the membership interests in Maalt Specialized Bulk, L.L.C. (“Maalt”) (See Note 10). Under the agreement, we could be required to make future additional payments not to exceed $3.0 million which are contingent on Maalt meeting certain financial and operational performance targets. Each year in the three-year period beginning December 6, 2011, we will determine whether Maalt has met the specified performance targets for the preceding year. In the event that Maalt has met the specified performance targets for the preceding year, we will make payments for such year based upon the number of specified performance targets met. We have accrued $0.5 million as of December 31, 2012 for future payments pursuant to this agreement.

On January 19, 2012, we entered into an agreement to acquire the assets and 90.0% of the profit interests in WWS for $2.4 million (See Note 4). Under the agreement, we could be required to make future additional payments to the sellers not to exceed $6.0 million to obtain the remaining 10.0% of the profit interests. These payments are contingent on the completion of certain operating targets, including the construction of new sand processing plants and those plants meeting certain production levels. No payments were required as of December 31, 2012.

We are involved in various lawsuits and disputes incidental to our business operations, including commercial disputes, personal injury claims, property damage claims and contract actions. We record an associated liability when a loss is probable and the amount is reasonably estimable. Although the outcome of litigation cannot be predicted with certainty, management is of the opinion that no pending or threatened lawsuit or dispute incidental to our business operations is likely to have a material adverse effect on our consolidated financial position, results of operations or cash flows. The final resolution of such matters could exceed amounts accrued and actual results could differ materially from management’s estimates.

We are self-insured up to certain retention limits with respect to workers’ compensation and general liability matters. We maintain accruals for self-insurance retentions that we estimate using third-party data and claims history. Included in operating costs is workers’ compensation expense of $11.6 million, $16.5 million and $7.9 million during the years ended December 31, 2012, 2011 and 2010, respectively.

Chesapeake’s stock-based compensation program in 2012, 2011 and 2010 consisted of restricted stock awarded to employees and non-employee directors. The fair value of the awards was determined based on the fair market value of the shares of Chesapeake common stock on the date of the grant. This value is amortized over the vesting period, which is generally four years from the date of the grant. To the extent compensation cost relates to employees directly involved in oilfield services operations, such amounts are charged to us and reflected as operating costs and general and administrative expenses. Included in operating costs and general and administrative expenses is stock-based compensation expense of $12.1 million, $10.9 million and $9.1 million for the years ended December 31, 2012, 2011 and 2010, respectively. Effective January 1, 2012, we reimburse Chesapeake for these costs in accordance with our administrative services agreement. To the extent compensation cost relates to employees indirectly involved in oilfield services operations, such amounts are charged to us through an overhead allocation and are reflected as general and administrative expenses.

A summary of the status and changes of the unvested shares of restricted stock related to employees directly involved in oilfield services operations is presented below.

The aggregate intrinsic value of restricted stock vested for the year ended December 31, 2012, as reflected in the table above, was approximately $11.2 million based on the Chesapeake common stock price at the time of vesting.

As of December 31, 2012, there was $32.9 million of total unrecognized compensation cost related to the unvested restricted stock of employees involved directly in oilfield services operations. The cost is expected to be recognized over a weighted average period of approximately three years.

The components of the income tax expense (benefit) for each of the periods presented below are as follows:

The effective income tax expense (benefit) differed from the computed “expected” federal income tax expense on earnings before income taxes for the following reasons:

Deferred income taxes are provided to reflect temporary differences in the basis of net assets for income tax and financial reporting purposes. The tax-effected temporary differences and tax loss carryforwards which comprise deferred taxes are as follows:

At December 31, 2012, COO had federal income tax net operating loss (NOL) carryforwards of approximately $433.4 million. Of these carryforwards, $63.7 million is limited ($15.2 million annually) under Section 382 of the Internal Revenue Code. These limitations are a result of the acquisitions of Bronco and Rensco during 2011. The NOL carryforwards expire from 2031 through 2032. The value of these carryforwards depends on the ability of COO to generate taxable income.

In October 2011, we acquired 49% of the membership interests in Maalt for $12.0 million. Maalt provides bulk transportation, transloading and sand hauling services, and its assets consist primarily of trucks and trailers. We use the equity method of accounting to account for our investment in Maalt, which had a carrying value of $12.6 million as of December 31, 2012. We recorded positive equity method adjustments to our investment of $0.1 million for our share of Maalt’s income for the year ended December 31, 2012. We also made additional investments of $0.5 million during the year ended December 31, 2012. As of December 31, 2012, the carrying value of our investment in Maalt is in excess of the underlying equity in Maalt’s net assets by approximately $11.5 million. This excess is attributable to goodwill and will not be amortized.

In August 2011, we entered into an agreement with Big Star Field Services, L.L.C. to form Big Star Crude Co., L.L.C. (“Big Star”), a jointly controlled entity, which engages in the commercial trucking business. We are committed to contribute 85% of the capital requirements of this entity. We currently own 100% of the preferred voting units, which represent a 49% ownership interest on a fully diluted basis. We will receive a preferred return (85% of all distributions) until a 25% rate of return has been reached, at which time the preferred units will be converted to common units and future distributions will be based on equity ownership.

Big Star is considered a variable interest entity (“VIE”) because our voting rights are not proportional to our economic interests. Big Star entered into a fleet usage agreement with Chesapeake Energy Marketing, Inc. (“CEMI”), a wholly owned subsidiary of Chesapeake, whereby it dedicates 100% of its trucking fleet’s usage hours to providing crude hauling services exclusively for CEMI. We determined that CEMI is the primary beneficiary due to the fleet usage agreement and would therefore be the consolidating entity. Accordingly, we use the equity method of accounting to record our investment in Big Star, which had a carrying value of $5.6 million as of December 31, 2012. We recorded negative equity method adjustments of $0.5 million for the year ended December 31, 2012 for our share of Big Star’s results of operations. We also made additional investments of $1.4 million in Big Star during the year ended December 31, 2012. Our risk of loss related to Big Star is our investment balance.

The fair value measurement standard defines fair value as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (referred to as an “exit price”). Authoritative guidance on fair value measurements and disclosures clarifies that a fair value measurement for a liability should reflect the entity’s non-performance risk. In addition, a fair value hierarchy is established that prioritizes the inputs to valuation techniques used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted market prices in active markets for identical assets and liabilities (Level 1 measurements) and the lowest priority to unobservable inputs (Level 3 measurements). The three levels of the fair value hierarchy are:

Level 1- Unadjusted quoted prices in active markets that are accessible at the measurement date for identical, unrestricted assets or liabilities.

Level 2- Quoted prices in markets that are not active, or inputs which are observable, either directly or indirectly, for substantially the full term of the asset or liability. This category includes quoted prices for similar assets or liabilities in active markets; quoted prices for identical or similar assets or liabilities in markets that are not active; inputs other than quoted prices that are observable for the asset or liability; and inputs that are derived principally from or corroborated by observable market data by correlation or other means.

Level 3- Measured based on prices or valuation models that require inputs that are both significant to the fair value measurement and less observable from objective sources.

The carrying values of cash, trade receivables and trade payables are considered to be representative of their respective fair values due to the short-term nature of these instruments.

Fair value measurements were applied with respect to our non-financial assets and liabilities measured on a non-recurring basis, which consist primarily of goodwill, assets acquired and liabilities assumed in a business combination and long-lived asset impairments based on Level 3 inputs. See Notes 3 and 4 for additional discussion.

The fair value of debt is the estimated amount a market participant would have to pay to purchase our debt, including any premium or discount attributable to the difference between the stated interest rate and market rate of interest at the balance sheet date. Fair values are based on quoted market prices or average valuations of similar debt instruments at the balance sheet date for those debt instruments for which quoted market prices are not available. Estimated fair values are determined by using available market information and valuation methodologies. Considerable judgment is required in interpreting market data to develop the estimates of fair value. The use of different market assumptions or valuation methodologies may have a material effect on the estimated fair value amounts.

Financial instruments that potentially subject us to concentrations of credit risk consist principally of cash and trade receivables. Accounts receivable from Chesapeake and its affiliates were $337.7 million and $172.5 million as of December 31, 2012 and December 31, 2011, or 93% and 85%, respectively, of our total accounts receivable. The increase was due to extending Chesapeake’s payment terms from 30 days to 60 days in accordance with the master services agreement. Revenues from Chesapeake affiliates were $1.811 billion, $1.226 billion and $779.3 million for the years ended December 31, 2012, 2011 and 2010, or 94%, 94% and 96%, respectively. We believe that the loss of this customer would have a material adverse effect on our operating results as there can be no assurance that replacement customers would be identified and accessed in a timely fashion or at comparable margins.

In the normal course of business, drilling, hydraulic fracturing, oilfield rentals, trucking and fluid hauling and disposal services and compressor manufacturing are provided to Chesapeake and its affiliates. Substantially all of our revenues are derived from Chesapeake and its working interest partners (see Note 13).

International Association of Drilling Contractors drilling contracts. The specific terms of each request for other services are typically set forth in a field ticket, purchase order 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 provides 30 days written notice of termination, although such agreement may not be terminated during the term of the services agreement described below.

In October 2011, we entered into 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 rates, the lesser of 75 of our drilling rigs or 80% of our operational drilling rig fleet, each referred to as a “committed rig.” However, the number of committed rigs will be ratably reduced 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, to complete a minimum aggregate number of fracturing stages equal to 25 stages per month times the average number of our operational hydraulic fracturing fleets during such month, each referred to as a “committed stage.” However, the number of committed stages per month will be reduced 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 gives written notice of termination at least 45 days prior to the end of a term; provided, however, Chesapeake has the right to terminate the agreement, by written notice, within 30 days of our change in control. For purposes of the services agreement, a change of control is deemed to have occurred if Chesapeake no longer beneficially owns at least 51% of our outstanding equity interests. We did not receive any non-utilization fees pursuant to the agreement for the years ended December 31, 2012 and 2011.

In October 2011, we entered into a facilities lease agreement with Chesapeake pursuant to which we lease a number of the storage yards and physical facilities out of which we conduct our operations. The initial term of the lease agreement ends December 31, 2014, after which the agreement is automatically renewed in successive one-year terms until we or Chesapeake terminates it. During the renewal periods, the amount of rent charged by Chesapeake increases by 2.5% each year. We make monthly payments to Chesapeake under the lease agreement that cover rent and our proportionate share of maintenance, operating expenses, taxes and insurance. We incurred $10.1 and $1.8 million of lease expense for the years ended December 31, 2012 and 2011, respectively, under this lease agreement.

Chesapeake provides us with general and administrative services and the services of its employees pursuant to an administrative services agreement entered into in October 2011. These services include legal, accounting, treasury, environmental, safety, information technology and other corporate services. 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. The administrative expense allocation is determined by estimates of time devoted to COO entities by Chesapeake employees or COO employee headcount compared to Chesapeake headcount. All of the allocations of administrative costs are based on assumptions that management believes are reasonable; however, these allocations are not necessarily indicative of the costs and expenses that would have resulted if we had been operating as a stand-alone entity. The administrative services agreement has a five-year initial term and will thereafter automatically extend for successive one-year terms unless we or Chesapeake gives written notice of termination at least one year prior to the end of a term. Prior to October 2011, Chesapeake made allocations of administrative costs in a similar manner as the allocation under the administrative services agreement. These charges from Chesapeake were $49.4 million, $33.7 million and $23.9 million for the years ended December 31, 2012, 2011 and 2010, respectively.

that the aggregate monthly revenue generated by the number of trucking units in the dedicated fleet exceeds a certain threshold stated in the agreement. If this threshold is not met during any month, we must pay Maalt an amount equal to 90% of the difference between the minimum services threshold and the total revenue generated by the trucking units during the applicable month. No payments for non-utilization were required as of December 31, 2012.

Our revenues, income (loss) before income taxes and identifiable assets are primarily attributable to four reportable segments. Each of these segments represents a distinct type of business. These segments have separate management teams which report to our chief operating decision maker. The results of operations in these segments are regularly reviewed by the chief operating decision maker for purposes of determining resource allocation and assessing performance. Management evaluates the performance of our segments based upon earnings before interest, taxes, depreciation and amortization, as further adjusted to add back nonrecurring items. The following is a description of the segments and other operations:

Drilling. Our drilling segment provides land drilling and drilling-related services, including directional drilling, geosteering and mudlogging, for oil and natural gas exploration and development activities. As of December 31, 2012, we owned or leased a fleet of 119 land drilling rigs.

Hydraulic Fracturing. Our hydraulic fracturing segment provides hydraulic fracturing and other well stimulation 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 December 31, 2012, we owned seven hydraulic fracturing fleets with an aggregate of 270,000 horsepower.

Oilfield Trucking. Our oilfield trucking segment provides drilling rig relocation and logistics services as well as fluid handling services. Our trucks move drilling rigs, crude oil, other fluids and construction materials to and from the wellsite and also transport produced water from the wellsite. As of December 31, 2012, we owned a fleet of 278 rig relocation trucks, 66 cranes and forklifts and 250 fluid hauling trucks.

Other Operations. Our other operations primarily consist of our natural gas compressor manufacturing operations and corporate functions.

On October 28, 2011, COO issued and sold the Notes with an aggregate principal amount of $650.0 million (Note 5). Pursuant to the Indenture governing the Notes, the Notes are fully and unconditionally and jointly and severally guaranteed by all of our material subsidiaries. Each of the subsidiary guarantors is 100% owned by COO and there are no material subsidiaries of COO other than the subsidiary guarantors. Chesapeake Oilfield Finance, Inc. and Western Wisconsin Sand Company, LLC are minor non-guarantor subsidiares whose condensed consolidating financial information is included with the guarantor subsidiaries. COO has independent assets and operations. Condensed consolidating financial information with respect to the guarantors is presented below. There are no significant restrictions on the ability of COO or any subsidiary guarantor to obtain funds from its subsidiaries by dividend or loan.

Set forth below are condensed consolidating financial statements for COO (parent) on a stand-alone, unconsolidated basis, and its combined guarantor subsidiaries as of December 31, 2012 and December 31, 2011 and for each of the three years in the period ended December 31, 2012. The financial information may not necessarily be indicative of results of operations, cash flows or financial position had the subsidiaries operated as independent entities.

In May 2011, the FASB issued guidance on fair value measurement and disclosure requirements which expands existing fair value disclosure requirements, particularly for Level 3 inputs. The new requirements include quantitative disclosure of the unobservable inputs and assumptions used in the measurement; description of the valuation processes in place and sensitivity of the fair value to changes in unobservable inputs; and the level of items (in the fair value hierarchy) that are not measured at fair value in the balance sheet but whose fair value must be disclosed. The guidance was effective for interim and annual periods beginning on or after December 15, 2011. Adoption of this guidance had no impact on our financial position or results of operations.

Any material subsequent events have been considered for disclosure through April 5, 2013.

In January 2013, we sold eight drilling rigs and spare equipment for cash proceeds of approximately $27.3 million.

The accompanying notes are an integral part of these condensed consolidated financial statements.

The accompanying condensed consolidated financial statements and related notes present COO’s financial position as of March 31, 2013 and December 31, 2012, the results of operations and cash flows for the three months ended March 31, 2013 and 2012 and the changes in equity for the three months ended March 31, 2013. These notes relate to the three months ended March 31, 2013 (the “Current Quarter”) and the three months ended March 31, 2012 (the “Prior Quarter”).

The accompanying condensed consolidated financial statements were prepared using accounting principles generally accepted in the United States (“GAAP”) for interim financial information. All material adjustments (consisting solely of normal recurring adjustments) which, in the opinion of management, are necessary for a fair statement of the results for the interim periods have been reflected. Certain footnote disclosures normally included in the financial statements prepared in accordance with GAAP have been appropriately condensed or omitted. COO’s audited consolidated financial statements for the year ended December 31, 2012 include certain definitions and a summary of significant accounting policies and should be read in conjunction with these interim condensed consolidated financial statements. To conform to the presentation of the March 31, 2013 financial statements, certain balances have been reclassified on the Prior Quarter statements of operations and statement of cash flows.

Chesapeake provides cash management services to COO through a centralized treasury system. Transactions between COO and Chesapeake have been identified in the financial statements as transactions between affiliates (see Note 11).

The accompanying condensed consolidated financial statements include 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. These charges from Chesapeake were $13.0 million and $11.2 million for the Current Quarter and Prior Quarter, respectively. Management believes that the allocated charges are representative of the costs and expenses incurred by Chesapeake for COO. See Note 11 for discussion of the methods of allocation.

We provide a wide range of wellsite services, including drilling, hydraulic fracturing, oilfield rentals, rig relocation, fluid handling and manufacturing of natural gas compressor packages. We conduct our operations in Colorado, Kansas, Louisiana, Montana, North Dakota, Ohio, Oklahoma, Pennsylvania, Texas, West Virginia, Wisconsin and Wyoming. As of March 31, 2013, our primary owned operating assets consisted of 48 drilling rigs, eight hydraulic fracturing fleets, 286 rig relocation trucks, 67 cranes and forklifts and 254 trucks for fluid handling. Additionally, we had 68 rigs leased under contracts at March 31, 2013 (see Note 4). Our reportable business segments are drilling, hydraulic fracturing, oilfield rentals, oilfield trucking and other operations (see Note 12).

On October 28, 2011, we issued $650.0 million in aggregate principal amount of 6.625% Senior Notes due 2019 (the “2019 Senior Notes” or the “Notes”) in a private placement. We incurred $14.8 million in financing costs related to the Notes issuance which have been deferred and are being amortized over the life of the 2019 Senior Notes. We used the net proceeds of $637.0 million from the 2019 Senior Notes issuance to pay down a portion of our affiliate debt with Chesapeake. The 2019 Senior Notes will mature on November 15, 2019 and interest is payable semi-annually on each of May 15 and November 15. COO and Chesapeake Oilfield Finance, Inc., our wholly owned subsidiary, are the co-issuers of the 2019 Senior Notes.

We may redeem up to 35% of the 2019 Senior Notes with proceeds of certain equity offerings at a redemption price of 106.625% of the principal amount plus accrued and unpaid interest prior to November 15, 2014, subject to certain conditions. Prior to November 15, 2015, we may redeem some or all of the 2019 Senior Notes at a price equal to 100% of the principal amount plus a make-whole premium determined pursuant to a formula set forth in the Indenture governing the 2019 Senior Notes, plus accrued and unpaid interest. On and after November 15, 2015, we may redeem all or part of the 2019 Senior Notes at the following prices (as a percentage of principal), plus accrued and unpaid interest, if redeemed during the 12-month period beginning on November 15 of the years indicated below:

The 2019 Senior Notes are subject to covenants that, among other things, limit our ability and the ability of certain of our subsidiaries to: (1) sell assets; (2) declare dividends or make distributions on our equity interests or purchase or redeem our equity interests; (3) make investments or other specified restricted payments; (4) incur or guarantee additional indebtedness and issue disqualified or preferred equity; (5) create or incur certain liens; (6) enter into agreements that restrict the ability of our restricted subsidiaries to pay dividends, make intercompany loans or transfer assets to us; (7) effect a merger, consolidation or sale of all or substantially all of our assets; (8) enter into transactions with affiliates; and (9) designate subsidiaries as unrestricted subsidiaries. We were in compliance with these covenants as of March 31, 2013. The 2019 Senior Notes also have cross default provisions that apply to other indebtedness COO or any of its guarantor subsidiaries may have from time to time with an outstanding principal amount of $50.0 million or more. If the 2019 Senior Notes achieve an investment grade rating by either of Moody’s Investors Service, Inc. (“Moody’s”) or Standard & Poor’s Rating Services (“S&P”), our obligation to comply with certain of these covenants will be suspended, and if the Notes achieve an investment grade rating from both of Moody’s and S&P, then such covenants will terminate.

Under a registration rights agreement, we agreed to file a registration statement within 365 days after the closing of the Notes offering enabling holders of the Notes to exchange the privately placed Notes for publicly registered exchange notes with substantially the same terms. We are required to use our commercially reasonable best efforts to cause the registration statement to become effective as soon as practicable after filing and to consummate the exchange offer on the earliest practicable date after the registration statement has become effective, but in no event later than 60 days after the date the registration statement has become effective. We also agreed to make additional interest payments, up to a maximum of 1.0% per annum, to holders of the Notes if we do not comply with our obligations under the registration rights agreement. We did not file a registration statement within 365 days after the closing of the Notes offering and as of March 31, 2013, had accrued approximately $0.9 million of additional expense related to this delay, which was paid on May 15, 2013. We filed the registration statement on April 5, 2013. The Notes are guaranteed by all of our existing subsidiaries, other than certain immaterial subsidiaries.

On November 3, 2011, we entered into a five-year senior secured revolving bank credit facility (the “Credit Facility”) with total commitments of $500.0 million. We incurred $5.4 million in financing costs related to entering into the Credit Facility which have been deferred and are being amortized over the life of the Credit Facility. The borrowing capacity of the Credit Facility may be increased to $900.0 million at our option, subject to compliance with the restrictive covenants in the Credit Facility and in the indenture governing our 2019 Senior Notes, as well as lender approval. The maximum amount that we may borrow under the Credit Facility may be subject to limitations due to certain covenants contained in the Credit Facility. As of March 31, 2013, the Credit Facility was not subject to any such limitations. The Credit Facility is used to fund capital expenditures and for general corporate purposes associated with our operations. Borrowings under the Credit Facility are secured by liens on our equity interests and the equity interests of our current and future guarantor subsidiaries and all of our guarantor subsidiaries’ assets, including real and personal property, and bear interest at our option at either (i) 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 (ii) 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. The unused portion of the Credit Facility is subject to a commitment fee that varies from 0.375% to 0.50% per annum, according to our leverage ratio. We recorded commitment fee expense of $0.1 million and $0.5 million for the Current Quarter and Prior Quarter, respectively. Interest is payable quarterly or, if LIBOR applies, it may be payable at more frequent intervals. COO is the borrower under the Credit Facility.

The Credit Facility contains various covenants and restrictive provisions which limit our and our subsidiaries’ ability to incur additional indebtedness, make investments or loans and create liens. The Credit Facility requires maintenance of a leverage ratio, a senior secured leverage ratio and a fixed charge coverage ratio, in each case as defined in the Credit Facility agreement. We were in compliance with these covenants as of March 31, 2013. If we or our subsidiaries should fail to perform our obligations under these and other covenants, the Credit Facility could be terminated and any outstanding borrowings under the Credit Facility could be declared immediately due and payable. Such acceleration, if involving a principal amount of $50.0 million or more, would constitute an event of default under our 2019 Senior Notes indenture, which could in turn result in the acceleration of the senior note indebtedness. The Credit Facility also contains cross default provisions that apply to other indebtedness, including our 2019 Senior Notes, that we and our subsidiaries may have from time to time with an outstanding principal amount in excess of $15.0 million.

No scheduled principal payments are required on any of our long-term debt until November 2016, when our Credit Facility becomes due.

Other current and long-term liabilities as of March 31, 2013 and December 31, 2012 are detailed below:

Rent expense for rigs, real property and rail cars for the Current Quarter and Prior Quarter was $29.7 million and $29.9 million, respectively, and was included in operating costs in our condensed consolidated statements of operations.

In a series of transactions beginning in 2006, we sold 94 drilling rigs (of which 26 have been repurchased) and related equipment and entered into master lease agreements under which we agreed to lease the rigs from the buyers for initial terms ranging from five to ten years. These transactions were recorded as sales and operating leasebacks and any related net gains are amortized to operating expense over the lease term. The deferred gains, net of fees, are included in other current liabilities and other long-term liabilities on our condensed consolidated balance sheets. We amortized $1.5 million and $1.8 million to operating expense related to the deferred gains for the Current Quarter and Prior Quarter, respectively.

On October 1, 2011, we entered into a facilities lease agreement with Chesapeake pursuant to which we lease a number of the storage yards, office space 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 is automatically renewed for successive one-year terms until we or Chesapeake terminate it. During the renewal periods, the amount of rent charged by Chesapeake increases by 2.5% each year. We make monthly payments to Chesapeake under the lease agreement that cover rent and our proportionate share of maintenance, operating expenses, taxes and insurance. These leases are being accounted for as operating leases.

As of March 31, 2013, we were a party to five lease agreements with various third parties to lease rail cars for initial terms of five to seven years. Additional rental payments are required for the use of rail cars in excess of the allowable mileage stated in the respective agreements. These leases are being accounted for as operating leases.

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

Much of the equipment we purchase requires long production lead times. As a result, we usually have outstanding orders and commitments for such equipment. As of March 31, 2013, we had $84.5 million of purchase obligations related to future capital expenditures primarily for drilling rigs and related equipment and hydraulic fracturing equipment that we expect to incur in 2013.

On October 7, 2011, we entered into an agreement to acquire 49% of the membership interests in Maalt Specialized Bulk, L.L.C. (“Maalt”) (see Note 7). Under the agreement, we could be required to make future additional payments not to exceed $3.0 million which are contingent on Maalt meeting certain financial and operational performance targets. Each year in the three-year period beginning December 6, 2011, we will determine whether Maalt has met the specified performance targets for the preceding year. In the event that Maalt has met the specified performance targets for the preceding year, we will make payments for such year based upon the number of specified performance targets met. As of March 31, 2013, we had accrued $0.2 million for future payments pursuant to this agreement.

We have also entered into a transportation services and usage agreement with Maalt under which Maalt has dedicated a portion of its trucking fleet to allow us to meet our sand transportation needs. The size of the dedicated fleet will be determined on a monthly basis based on our projected needs and agreed upon by both parties. We have guaranteed to Maalt that we will utilize its services at such a rate that the aggregate monthly revenue generated by the number of trucking units in the dedicated fleet exceeds a certain threshold stated in the agreement. If this threshold is not met during any month, we must pay Maalt an amount equal to 90% of the difference between the minimum services threshold and the total revenue generated by the trucking units during the applicable month. As of March 31, 2013, we had accrued $0.2 million for future payments pursuant to this agreement.

We are self-insured up to certain retention limits with respect to workers’ compensation and general liability matters. We maintain accruals for self-insurance retentions that we estimate using third-party data and claims history. Included in operating costs is workers’ compensation expense of $1.9 million and $3.8 million during the Current Quarter and Prior Quarter, respectively.

Chesapeake’s stock-based compensation program consists of restricted stock awarded to employees and non-employee directors and performance share units (PSUs) to senior management.

The fair value of the restricted stock awards was determined based on the fair market value of the shares of Chesapeake common stock on the date of the grant. This value is amortized over the vesting period, which is generally four years from the date of the grant. To the extent compensation cost relates to employees directly involved in oilfield services operations, such amounts are charged to us and reflected as operating costs and general and administrative expenses. Included in operating costs and general and administrative expenses is stock-based compensation expense of $2.9 million and $3.2 million for the Current Quarter and Prior Quarter, respectively. Effective January 1, 2012, we reimburse Chesapeake for these costs in accordance with our administrative services agreement. To the extent compensation cost relates to employees indirectly involved in oilfield services operations, such amounts are charged to us through an overhead allocation and are reflected as general and administrative expenses.

A summary of the status and changes of the unvested shares of restricted stock related to employees directly involved in oilfield services operations is presented below.

The aggregate intrinsic value of restricted stock vested for the Current Quarter, as reflected in the table above, was approximately $5.1 million based on the Chesapeake common stock price at the time of vesting.

As of March 31, 2013, there was $38.1 million of total unrecognized compensation cost related to the unvested restricted stock of employees involved directly in oilfield services operations. The cost is expected to be recognized over a weighted average period of approximately three years.

In January 2012 and 2013, Chesapeake granted PSUs to certain members of COO’s senior management under a Long Term Incentive Plan that include both an internal performance measure and an external market condition. The 2012 awards vest over one-, two- and three-year performance periods, and the 2013 awards vest over a three-year service period. The internal performance measure is considered a performance condition with a fair value generally equal to Chesapeake’s common stock price. The external market condition is considered a market condition and generally requires Monte Carlo simulation to determine the fair value. The latter calculation for the 2012 awards is based on the absolute total shareholder return (TSR) of Chesapeake common stock and the relative TSR of Chesapeake common stock compared to the TSR of certain peers. The calculation for the 2013 awards is based on the relative TSR of Chesapeake common stock compared to the TSR of certain peers.

For PSUs granted in 2012, each of the TSR and operational payout components can range from 0% to 125%. For PSUs granted in 2013, the TSR component can range from 0% to 125% and each of the two operational components can range from 0% to 62.5%, in each case resulting in a total range of payout from 0% to 200%. The PSUs can only be settled in cash, so they are classified as a liability in our condensed consolidated financial statements and are measured at fair value as of the grant date, with such value re-measured at the end of each reporting period. Compensation expense is recognized over the vesting period with a corresponding adjustment to the liability.

As of the respective grant dates, the fair value of the 8,475 PSUs issued in 2012 was $0.2 million and the fair value of the 60,130 PSUs issued in 2013 was $1.3 million. As of March 31, 2013, the fair value of the PSUs was $1.6 million. We have recorded $0.1 million of this value as a short-term liability for PSUs that will be settled in January 2014 and $0.2 million as a long-term liability representing the portion of the award that will be settled in January 2015 or thereafter. The remaining $1.3 million relates to PSUs for which the requisite service period has not been completed.

Chesapeake and its subsidiaries historically have filed a consolidated federal income tax return and other state returns as required. COO and its subsidiaries are limited liability companies, and as a result, 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 COO 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 as if each entity were a corporation, regardless of its actual characterization of U.S. federal income tax purposes. Any current taxes resulting from application of the separate return method will be paid in cash unless limited by the terms of our indenture and revolving credit facility, in which case such amounts will be treated as a capital contribution.

In October 2011, we acquired 49% of the membership interests in Maalt for $12.0 million. Maalt provides bulk transportation, transloading and sand hauling services, and its assets consist primarily of trucks and trailers. We use the equity method of accounting to account for our investment in Maalt, which had a carrying value of $12.7 million as of March 31, 2013. We recorded equity method adjustments to our investment of ($0.1) million and $0.2 million for our share of Maalt’s income (loss) for the Current Quarter and Prior Quarter, respectively. We also made additional investments of $0.2 million during the Current Quarter. As of March 31, 2013, the carrying value of our investment in Maalt is in excess of the underlying equity in Maalt’s net assets by approximately $11.7 million. This excess is attributable to goodwill recorded on Maalt’s financial statements and will not be amortized.

In August 2011, we entered into an agreement with Big Star Field Services, L.L.C. to form Big Star Crude Co., L.L.C. (“Big Star”), a jointly controlled entity, which engages in the commercial trucking business. We currently own 100% of the preferred voting units, which represent a 49% ownership interest on a fully diluted basis. We will receive a preferred return (85% of all distributions) until a 25% rate of return has been reached, at which time the preferred units will be converted to common units and future distributions will be based on equity ownership.

Big Star is considered a variable interest entity (“VIE”) because our voting rights are not proportional to our economic interests. Big Star entered into a fleet usage agreement with Chesapeake Energy Marketing, Inc. (“CEMI”), a wholly owned subsidiary of Chesapeake, whereby it dedicates 100% of its trucking fleet’s usage hours to providing crude hauling services exclusively for CEMI. We determined that CEMI is the primary beneficiary due to the fleet usage agreement and would therefore be the consolidating entity. Accordingly, we use the equity method of accounting to record our investment in Big Star, which had a carrying value of $5.5 million as of March 31, 2013. We recorded equity method adjustments to our investment of a nominal amount and ($0.3) million for our share of Big Star’s income (loss) for the Current Quarter and Prior Quarter, respectively. Our risk of loss related to Big Star is our investment balance.

Level 1- Unadjusted quoted prices in active markets that are accessible at the measurement date for identical, unrestricted assets or liabilities.

Level 3- Measured based on prices or valuation models that require inputs that are both significant to the fair value measurement and less observable from objective sources.

The carrying values of cash, trade receivables and trade payables are considered to be representative of their respective fair values due to the short-term nature of these instruments.

Financial instruments that potentially subject us to concentrations of credit risk consist principally of cash and trade receivables. Accounts receivable from Chesapeake and its affiliates were $423.9 million and $337.7 million as of March 31, 2013 and December 31, 2012, or 95% and 93%, respectively, of our total accounts receivable. Revenues from Chesapeake and its affiliates were $513.4 million and $420.8 million for the Current Quarter and Prior Quarter, or 94% and 94%, respectively. We believe that the loss of this customer would have a material adverse effect on our operating results as there can be no assurance that replacement customers would be identified and accessed in a timely fashion or at comparable margins.

In the normal course of business, we provide drilling, hydraulic fracturing, oilfield rentals, trucking and fluid handling services and compressor manufacturing to Chesapeake and its affiliates. Substantially all of our revenues are derived from Chesapeake and its working interest partners (see Note 10).

In October 2011, we entered into 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 International Association of Drilling Contractors drilling contracts. The specific terms of each request for other services are typically set forth in a field ticket, purchase order 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 provides 30 days written notice of termination, although such agreement may not be terminated during the term of the services agreement described below.

number of committed stages per month will be reduced 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 gives written notice of termination at least 45 days prior to the end of a term; provided, however, Chesapeake has the right to terminate the agreement, by written notice, within 30 days of our change in control. For purposes of the services agreement, a change of control is deemed to have occurred if Chesapeake no longer beneficially owns at least 51% of our outstanding equity interests. We did not receive any non-utilization fees pursuant to the agreement for the Current Quarter or Prior Quarter.

In October 2011, we entered into a facilities lease agreement with Chesapeake pursuant to which we lease a number of the storage yards and physical facilities out of which we conduct our operations. The initial term of the lease agreement ends December 31, 2014, after which the agreement is automatically renewed in successive one-year terms until we or Chesapeake terminates it. During the renewal periods, the amount of rent charged by Chesapeake increases by 2.5% each year. We make monthly payments to Chesapeake under the lease agreement that cover rent and our proportionate share of maintenance, operating expenses, taxes and insurance. We incurred $4.3 million and $1.7 million of lease expense for the Current Quarter and Prior Quarter, respectively, under this lease agreement.

Chesapeake provides us with general and administrative services and the services of its employees pursuant to an administrative services agreement entered into in October 2011. These services include legal, accounting, treasury, environmental, safety, information technology and other corporate services. 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. The administrative expense allocation is determined by estimates of time devoted to COO entities by Chesapeake employees or COO employee headcount compared to Chesapeake headcount. All of the allocations of administrative costs are based on assumptions that management believes are reasonable; however, these allocations are not necessarily indicative of the costs and expenses that would have resulted if we had been operating as a stand-alone entity. The administrative services agreement has a five-year initial term and will thereafter automatically extend for successive one-year terms unless we or Chesapeake gives written notice of termination at least one year prior to the end of a term. These charges from Chesapeake were $13.0 million and $11.2 million for the Current Quarter and Prior Quarter, respectively.

We are a party to a transportation services and usage agreement with Maalt under which Maalt has dedicated a portion of its trucking fleet to allow us to meet our sand transportation needs. The size of the dedicated fleet is determined on a monthly basis based on our projected needs and agreed upon by both parties. We have guaranteed to Maalt that we will utilize its services at such a rate that the aggregate monthly revenue generated by the number of trucking units in the dedicated fleet exceeds a certain threshold stated in the agreement. If this threshold is not met during any month, we must pay Maalt an amount equal to 90% of the difference between the minimum services threshold and the total revenue generated by the trucking units during the applicable month. We have accrued $0.2 million as of March 31, 2013 for future payments pursuant to this agreement.

Hydraulic Fracturing. Our hydraulic fracturing segment provides hydraulic fracturing and other well stimulation 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, 2013, we operated eight hydraulic fracturing fleets with an aggregate of 315,000 horsepower.

Other Operations. Our other operations primarily consist of our natural gas compressor manufacturing operations and corporate functions.

On October 28, 2011, our parent entity, “COO-parent”, issued and sold the Notes with an aggregate principal amount of $650.0 million (see Note 2). Pursuant to the Indenture governing the Notes, the Notes are fully and unconditionally and jointly and severally guaranteed by all of our material subsidiaries. Each of the subsidiary guarantors is 100% owned by COO-parent and there are no material subsidiaries of COO-parent other than the subsidiary guarantors. Chesapeake Oilfield Finance, Inc. and Western Wisconsin Sand Company, LLC are minor non-guarantor subsidiares whose condensed consolidating financial information is included with the guarantor subsidiaries. COO-parent has independent assets and operations. There are no significant restrictions on the ability of COO-parent or any subsidiary guarantor to obtain funds from its subsidiaries by dividend or loan.

Set forth below are condensed consolidating financial statements for COO-parent on a stand-alone, unconsolidated basis, and its combined guarantor subsidiaries as of March 31, 2013 and December 31, 2012 and for each of the three-month periods ended March 31, 2013 and 2012. The financial information may not necessarily be indicative of results of operations, cash flows or financial position had the subsidiaries operated as independent entities.

Any material subsequent events have been considered for disclosure through May 30, 2013.

We have audited the accompanying consolidated balance sheets of Bronco Drilling Company, Inc. and Subsidiaries (the “Company”) as of December 31, 2010 and 2009, and the related consolidated statements of operations, stockholders’ equity and comprehensive income (loss) and cash flows for each of the three years in the period ended December 31, 2010. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Bronco Drilling Company, Inc. and Subsidiaries as of December 31, 2010 and 2009, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2010, in conformity with accounting principles generally accepted in the United States of America.

The accompanying notes are an integral part of these consolidated financial statements.

CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY AND COMPREHENSIVE INCOME (LOSS)

The accompanying notes are an integral part of these consolidated financial statements.

Bronco Drilling Company, Inc. (the “Company”) provides contract land drilling services to oil and natural gas exploration and production companies. The accompanying consolidated financial statements include the Company’s accounts and the accounts of its wholly owned subsidiaries. All intercompany accounts and transactions have been eliminated in consolidation.

The Company has prepared the consolidated financial statements and related notes in accordance with accounting principles generally accepted in the United States of America. In preparing the financial statements, the Company made various estimates and assumptions that affect the amounts of assets and liabilities the Company reports as of the dates of the balance sheets and amounts the Company reports for the periods shown in the consolidated statements of operations, stockholders’ equity and cash flows. The Company’s actual results could differ significantly from those estimates. Material estimates that are particularly susceptible to significant changes in the near term relate to the Company’s recognition of revenues and accrued expenses, estimate of the allowance for doubtful accounts, estimate of asset impairments, estimate of deferred taxes and determination of depreciation and amortization expense.

A summary of the significant accounting policies consistently applied in the preparation of the accompanying consolidated financial statements follows.

The Company considers all highly liquid debt instruments purchased with a maturity of three months or less when acquired and money market mutual funds to be cash equivalents.

The Company maintains its cash and cash equivalents in accounts and instruments that may not be federally insured beyond certain limits. The Company has not experienced any losses in such accounts and believes it is not exposed to any significant credit risks on cash and cash equivalents.

At December 31, 2010, the Company had restricted cash of $2,700, at a bank in escrow related to the sale of drilling rigs.

The U.S. dollar is the functional currency for the Company’s consolidated operations. However, the Company has an equity investment in a Mexican entity whose functional currency is the peso. The assets and liabilities of the Mexican investment are translated into U.S. dollars based on the current exchange rate in effect at the balance sheet dates. Mexican income and expenses are translated at average rates for the periods presented. Translation adjustments have no effect on net income and are included in accumulated other comprehensive income in stockholders’ equity.

The Company earns contract drilling revenue under daywork and footage contracts.

Revenues on daywork contracts are recognized based on the days completed at the dayrate each contract specifies. Mobilization revenues and costs for daywork contracts are deferred and recognized over the days of actual drilling.

The Company follows the percentage-of-completion method of accounting for footage contract 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. Percentage-of-completion is determined based upon the amount of expenses incurred through the measurement date as compared to total estimated expenses to be incurred drilling the well. Mobilization costs are not included in costs incurred for percentage-of-completion calculations. Mobilization costs on footage contracts are deferred and recognized over the days of actual drilling. Under the percentage-of-completion method, management estimates are relied upon in the determination of the total estimated expenses to be incurred drilling the well. When estimates of revenues and expenses indicate a loss on a contract, the total estimated loss is accrued.

Revenue arising from claims for amounts billed in excess of the contract price or for amounts not included in the original contract are recognized when billed less any allowance for uncollectibility. Revenue from such claims is only recognized if it is probable that the claim will result in additional revenue, the costs for the additional services have been incurred, management believes there is a legal basis for the claim and the amount can be reliably estimated. Revenue from such claims are recorded only to the extent that contract costs relating to the claim have been incurred. Historically we have not billed any customers for amounts not included in the original contract.

The asset “unbilled receivables” represents revenues we have recognized in excess of amounts billed on drilling contracts in progress or costs deferred on daywork contracts in progress.

The Company records trade accounts receivable at the amount invoiced to customers. Substantially all of the Company’s accounts receivable are due from companies in the oil and gas industry. Credit is extended based on evaluation of a customer’s financial condition and, generally, collateral is not required. Accounts receivable are due within 30 days and are stated at amounts due from customers, net of an allowance for doubtful accounts when the Company believes collection is doubtful. Accounts outstanding longer than the contractual payment terms are considered past due. The Company determines its allowance by considering a number of factors, including the length of time trade accounts receivable are past due, the Company’s previous loss history, the customer’s current ability to pay its obligation to the Company and the condition of the general economy and the industry as a whole. The Company writes off specific accounts receivable when they become uncollectible and payments subsequently received on such receivables reduce the allowance for doubtful accounts. At December 31, 2010 and 2009, our allowance for doubtful accounts was $1,691 and $3,576, respectively.

Prepaid expenses include items such as insurance and fees. The Company routinely expenses these items in the normal course of business over the periods these expenses benefit.

Property and equipment, including renewals and betterments, are capitalized and stated at cost, while maintenance and repairs are expensed currently. Assets are depreciated on a straight-line basis. The depreciable lives of drilling rigs and related equipment are three to 15 years. The depreciable life of other equipment is three years. Depreciation is not commenced until acquired rigs are placed in service. Once placed in service, depreciation continues when rigs are being repaired, refurbished or between periods of deployment. Assets not placed in service and not being depreciated were $14,111 and $26,038 as of December 31, 2010 and 2009, respectively.

The Company capitalizes interest as a component of the cost of drilling rigs constructed for its own use. For the years ended December 31, 2010 and 2009, the Company did not capitalize any interest.

The Company evaluates for potential impairment of long-lived assets held for use and intangible assets subject to amortization when indicators of impairment are present, as defined in ASC Topic 360, Accounting for the Impairment or Disposal of Long-Lived

Assets. Circumstances that could indicate a potential impairment include significant adverse changes in industry trends, economic climate, legal factors, and an adverse action or assessment by a regulator. More specifically, significant adverse changes in industry trends include significant declines in revenue rates, utilization rates, oil and natural gas market prices and industry rig counts for drilling rigs and workover rigs. In performing an impairment evaluation, the Company estimates the future undiscounted net cash flows from the use and eventual disposition of long-lived assets and intangible assets grouped at the lowest level that cash flows can be identified. If the sum of the estimated future undiscounted net cash flows is less than the carrying amount of the long-lived assets and intangible assets for these asset grouping levels, then the Company would recognize an impairment charge. The amount of an impairment charge would be measured as the difference between the carrying amount and the fair value of these assets. See Note 9, Asset Sales and Held for Sale, for discussion of impairment of drilling rigs and related equipment due to their classification as held for sale. Assets held for sale are recorded at the lower of carrying amount or fair value less cost to sell. See Note 10, Discontinued Operations, for discussion of well servicing segment property and equipment impairment relating to its classification as held for sale. The assumptions used in the impairment evaluation for long-lived assets and intangible assets are inherently uncertain and require management judgment.

Debt issue costs and other assets consist of intangibles related to acquisitions, net of amortization, and debt issue costs, net of amortization. The Company follows Statement ASC Topic 323, “Intangibles — Goodwill and Other” to account for amortizable intangibles. Intangible assets that are acquired either individually or with a group of other assets are recognized based on its fair value and amortized over its useful life. The Company’s amortizable intangibles consist entirely of customer lists and relationships obtained through acquisitions. Customer lists and relationships are amortized over their estimated benefit period of four years. Depreciation and amortization expense includes amortization of intangibles of $78, $751, and $974 for the years ended December 31, 2010, 2009, and 2008, respectively. Total cost and accumulated amortization of intangibles at December 31, 2010 and 2009 was $2,318 and $2,318 and $3,705 and $3,403, respectively.

Legal fees and other debt issue costs incurred in obtaining financing are amortized over the term of the debt using a method which approximates the effective interest method. Gross debt issue costs were $2,669 and $2,232 at December 31, 2010 and 2009, respectively. Amortization expense related to debt issue costs was $688, $592, and $571 for the years ended December 31, 2010, 2009, and 2008, respectively, and is included in interest expense in the consolidated statements of operations. Accumulated amortization related to loan fees was $864 and $126 as of December 31, 2010 and 2009, respectively. On September 18, 2009 and September 29, 2008 the Company refinanced its revolving debt facility and incurred $2,232 and $3,501 of debt issuance costs, respectively. The Company wrote-off debt issue costs of $2,859, which is included in loss from early extinguishment of debt on the consolidated statement of operations for the year ended December 31, 2009.

Pursuant to Statement ASC Topic 740, Income Taxes, the Company follows the asset and liability method of accounting for income taxes, under which the Company recognizes 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. Deferred tax assets and liabilities were measured using enacted tax rates expected to apply to taxable income in the years in which the Company expects to recover or settle those temporary differences. A statutory Federal tax rate of 35% and effective state tax rate of 3.7% (net of Federal income tax effects) were used for the enacted tax rates for all periods.

As changes in tax laws or rates are enacted, deferred income tax assets and liabilities are adjusted through the provision for income taxes. Deferred tax assets are reduced by a valuation allowance if, based on available evidence, it is more likely than not that some portion or all of the deferred tax assets will not be realized. The classification of current and noncurrent deferred tax assets and liabilities is based primarily on the classification of the assets and liabilities generating the difference.

statement recognition and measurement of a tax position taken or expected to be taken in a tax return. The Company recognizes interest and/or penalties related to income tax matters as income tax expense. As of December 31, 2010, the tax years ended December 31, 2006 through December 31, 2009 are open for examination by U.S. taxing authorities.

Comprehensive income (loss) is comprised of net income (loss) and other comprehensive income. Other comprehensive income includes the translation adjustments of the financial statements of Bronco MX at December 31, 2010 and 2009. The following table sets forth the components of comprehensive income (loss):

The Company computes and presents net income (loss) per common share in accordance with ASC Topic 260, Earnings per Share. This standard requires dual presentation of basic and diluted net income (loss) per share on the face of the Company’s statement of operations. Basic net income (loss) per common share is computed by dividing net income or loss attributable to common stock by the weighted average number of common shares outstanding for the period. Diluted net income (loss) per common share reflects the potential dilution that could occur if options or other contracts to issue common stock were exercised or converted into common stock.

The Company has adopted ASC Topic 718, Stock Compensation upon granting its first stock options on August 16, 2005. ASC Topic 718 requires a public entity to measure the costs of employee services received in exchange for an award of equity or liability instruments based on the grant-date fair value of the award. That cost will be recognized over the periods during which an employee is required to provide service in exchange for the award.

Investee companies that are not consolidated, but over which the Company exercises significant influence, are accounted for under the equity method of accounting. Whether or not the Company exercises significant influence with respect to an Investee depends on an evaluation of several factors including, among others, representation on the Investee company’s board of directors and ownership level, which is generally a 20% to 50% interest in the voting securities of the Investee company. Under the equity method of accounting, an Investee company’s accounts are not reflected within the Company’s Consolidated Balance Sheets and Statements of Operations; however, the Company’s share of the earnings or losses of the Investee company is reflected in the caption “Equity in income (loss) of Challenger” and “Equity in income (loss) of Bronco MX” in the Consolidated Statements of Operations. The Company’s carrying value in an equity method Investee company is reflected in the caption “Investment in Challenger” and “Investment in Bronco MX” in the Company’s Consolidated Balance Sheets.

In December 2010, the FASB issued an accounting standard update that addresses the disclosure of supplementary pro forma information for business combinations. This update clarifies that when public entities are required to disclose pro forma information for business combinations that occurred in the current reporting period, the pro forma information should be presented as if the business combination occurred as of the beginning of the previous fiscal year when comparative financial statements are presented. This update is effective prospectively for business combinations for which the acquisition date is on or after the beginning of the first annual reporting period beginning on or after December 15, 2010. Early adoption is permitted. The Company is currently evaluating the impact, if any, the adoption will have on our consolidated financial statements.

In January 2010, the FASB issued a new accounting standard which requires reporting entities to provide information about movements of assets among Levels 1 and 2 of the three-tier fair value hierarchy established by ASC 820, Fair Value Measurements. Also required will be a reconciliation of purchases, sales, issuance, and settlements of financial instruments valued with a Level 3 method, which is used to price the hardest to value instruments. Entities will have to provide fair value measurement disclosures for each class of financial assets and liabilities. The guidance will be effective for fiscal years beginning after December 15, 2010. The Company is currently evaluating the impact, if any, the adoption will have on our consolidated financial statements.

In December 2009, the FASB issued a new accounting standard which updates the quantitative-based risks and rewards calculation for determining which reporting entity, if any, has a controlling financial interest in a variable interest entity with an approach focused on identifying which reporting entity has the power to direct the activities of a variable interest entity that most significantly impact the entity’s economic performance and (1) the obligation to absorb losses of the entity or (2) the right to receive benefits from the entity. An approach that is expected to be primarily qualitative will be more effective for identifying which reporting entity has a controlling financial interest in a variable interest entity. The amendments in this update also require additional disclosures about an reporting entity’s involvement in variable interest entities, which will enhance the information provided to users of financial statements. This new standard is effective at the start of a reporting entity’s first fiscal year beginning after January 1, 2010. The adoption of this standard did not impact our consolidated financial statements.

In October 2009, the FASB issued a new accounting standard that addresses the accounting for multiple-deliverable revenue arrangements to enable vendors to account for deliverables separately rather than as a combined unit. This new standard addresses how to separate deliverables and how to measure and allocate arrangement consideration to one or more units of accounting. Existing accounting standards require a vendor to use objective and reliable evidence of fair value for the undelivered items or the residual method to separate deliverables in a multiple-deliverable arrangement. Under the new standard, it is expected that multiple-deliverable arrangements will be separated in more circumstances than under current requirements. The new standard establishes a hierarchy for determining the selling price of a deliverable for purposes of allocating revenue to multiple deliverables. The selling price used will be based on vendor-specific objective evidence if available, third-party evidence if vendor-specific objective evidence is not available, or estimated selling price if neither vendor-specific objective evidence nor third-party evidence is available. The new standard must be prospectively applied to all revenue arrangements entered into in fiscal years beginning on or after June 15, 2010 and became effective for us on January 1, 2011. The Company is currently evaluating the impact, if any, the adoption will have on our consolidated financial statements.

In June 2009, the FASB issued a new accounting standard that amends the accounting and disclosure requirements for the consolidation of variable interest entities. This new standard removes the previously existing exception from applying consolidation guidance to qualifying special-purpose entities and requires ongoing reassessments of whether an enterprise is the primary beneficiary of a variable interest entity. Before this new standard, generally accepted accounting principles required reconsideration of whether an enterprise is the primary beneficiary of a variable interest entity only when specific events occurred. This new standard is effective as of the beginning of each reporting entity’s first annual reporting period that begins after November 15, 2009, for interim periods within that first annual reporting period, and for interim and annual reporting periods thereafter. This new standard became effective for us on January 1, 2010. The adoption of this standard did not impact our consolidated financial statements.

Certain amounts in the financial statements for the prior years have been reclassified to conform to the current year’s presentation.

On January 4, 2008, we acquired a 25% equity interest in Challenger Limited, in exchange for six drilling rigs and cash. The Company also sold to Challenger four drilling rigs and ancillary equipment. The Company recorded equity in loss of investment of $984 and $1,914 for the years ended December 31, 2010 and 2009, respectively, related to its equity investment in Challenger. Challenger is an international provider of contract land drilling and workover services to oil and natural gas companies with its principal operations in Libya.

The Company entered into a term note with Challenger related to the sale of four drilling rigs and ancillary equipment. The term note bears interest at 8.5%. Interest and principal payments of $529 on the note are due quarterly until maturity at February 2, 2011. The note receivable is collateralized by the assets sold to Challenger. The note receivable from Challenger at December 31, 2010 was $1,607, all of which was classified as current. The note receivable from Challenger at December 31, 2009 was $2,517.

On February 20, 2008, the Company entered into a Management Services Agreement and Master Services Agreement with Challenger. The Company agreed to make available to Challenger certain employees of the Company for the purpose of providing land drilling services, certain business consulting services and managerial support to Challenger. The Company invoices Challenger monthly for the services provided. The Company had accounts receivable from Challenger of $1,508 and $2,499 at December 31, 2010 and December 31, 2009, respectively, related to these services provided.

At December 31, 2010, the book value of the Company’s ordinary share investment in Challenger was $38,730. The Company’s 25% interest of the net assets of Challenger was estimated to be $35,428. The basis difference between the Company’s ordinary equity investment in Challenger and the Company’s 25% interest of the net assets of Challenger primarily consists of certain property, plant and equipment and accumulated depreciation in the amount of $3,626 and $324, respectively, at December 31, 2010. These amounts are being amortized against the Company’s 25% interest of Challenger’s net income over the estimated useful lives of 15 years for the property, plant and equipment. Amortization recorded during years ended December 31, 2010 and 2009 was $264 and $1,026, respectively.

The Company reviews its investment in Challenger for impairment based on the guidance of ASC Topic 323, Investments-Equity Method and Joint Venture, which states that a loss in value of an investment which is other than a temporary decline should be recognized. Evidence of a loss in value might include the absence of an ability to recover the carrying amount of the investment or inability of the investee to sustain an earnings capacity which would justify the carrying amount of the investment. A current fair value of an investment that is less than its carrying amount may indicate a loss in value of the investment. Due to the recent volatility and decline in oil and natural gas prices, a deteriorating global economic environment and the anticipated future earnings of Challenger, the Company deemed it necessary to test the investment for impairment in 2008, 2009 and 2010. Fair value of the investment was estimated using a combination of income, or discounted cash flows approach, and the market approach, which utilizes comparable companies’ data. The analysis resulted in an impairment charge of $14,442 during 2008. The analysis resulted in a fair value of $39,800 related to our investment in Challenger as of September 30, 2009, which was below the carrying value of the investment and resulted in a non-cash impairment charge in the amount of $21,247.

The analysis performed at December 31, 2010, resulted in a fair value of $40,863 related to our investment in Challenger, which was above the carrying value of the investment and resulted in no impairment. The estimate of fair value required management to make many estimates and judgments, such as forecasts of future cash flows, discount rates of approximately 15.0% and long term growth rates of 3.0% which it believes were reasonable and appropriate at December 31, 2010. Changes in such assumptions can result in an estimate of fair value that could be below the carrying amount of our investment in Challenger.

Recent civil and political disturbances in Libya the elsewhere in North Africa, and the Middle East that developed during the first quarter of 2011 may affect Challenger’s operations. Ongoing political unrest may result in loss of revenue and damage to equipment. Any impact from the political turmoil in Libya and elsewhere in North Africa on Challenger’s operations could negatively impact the Company’s investment in Challenger including, the entire loss of our investment.

In September 2009, Carso Infraestructura y Construcción, S.A.B. de C.V., or CICSA, purchased from us 60% of the outstanding membership interests of Bronco MX. Upon closing of the transaction, the Company owned the remaining 40% of the outstanding membership interests of Bronco MX. Immediately prior to the sale of the membership interests in Bronco MX to CICSA, the Company contributed six drilling rigs (Nos. 4, 43, 53, 58, 60 and 72), and the future net profit from rig leases relating to three additional drilling rigs (Nos. 55, 76 and 78), which the Company contributed to Bronco MX upon the expiration of the leases relating to such rigs. The general specifications of the contributed rigs are as follows:

The Company received $31,735 from CICSA in exchange for the 60% membership interest in Bronco MX, which included reimbursement for 60% of value added taxes previously paid by, or on behalf of, Bronco MX as a result of the importation to Mexico of the six drilling rigs that were contributed by the Company to Bronco MX. Upon completion of the transaction, the Company treated Bronco MX as a deconsolidated subsidiary in order to compute a loss in accordance with ASC Topic 810, Consolidation, due to the Company not retaining a controlling financial interest in Bronco MX subsequent to the sale. The Company recorded a net loss of $23,964 for the nine months ended September 30, 2009 relating to the transactions. The loss was computed based on the proceeds received from CICSA of $31,735 and the value of the Company’s 40% retained interest in Bronco MX of $21,495 less the book value of the net assets of Bronco MX, including rigs contributed to Bronco MX, of $77,194. The Company recorded a negative adjustment to the loss during the year ended December 31, 2010 of $1,487 due to post closing adjustments. Fair value of the Company’s 40% investment in Bronco MX was estimated using a combination of income, or discounted cash flows approach, the market approach, which utilizes pricing of third-party transactions of comparable businesses or assets and the cost approach which considers replacement cost as the primary indicator of value. The analysis resulted in a fair value of $21,495 related to the Company’s 40% retained interest in Bronco MX. At December 31, 2010, the book value of the Company’s ordinary share investment in Bronco MX was $20,632. The Company recorded equity in income (loss) of investment of $22 and ($588) for the year ended December 31, 2010 and for the period September 18 through December 31, 2009, respectively, related to its equity investment in Bronco MX. The Company’s investment in Bronco MX was increased by $474 as a result of a currency translation gain for the year ended December 31, 2010.

On July 1, 2010, CICSA contributed cash of approximately $45,100 in exchange for 735,356,219 shares of Bronco MX. As a result of the contribution, the Company’s membership interest in Bronco MX was decreased to approximately 20%. The Company accounted for the share issuance as if the Company had sold a proportionate amount of its shares. The Company recorded a loss on the transaction in the amount of $1,271.

Bronco MX is jointly managed, with CICSA having four representatives on its board of managers and the Company having one representative on its board of managers. The Company and CICSA, and their respective affiliates, have agreed to conduct all future land drilling and workover rig services, rental, construction, refurbishment, transportation, trucking and mobilization in Mexico and Latin America exclusively through Bronco MX, subject to Bronco MX’s ability to perform.

According to a Schedule 13D/A filed with the SEC on March 8, 2010 by Carlos Slim Helú, certain members of his family and affiliated entities (collectively, the “Slim Affiliates”), these individuals and entities collectively beneficially own approximately 19.99% of our common stock. CICSA is also a Slim Affiliate.

The Company adopted ASC Topic 740 on January 1, 2007. ASC Topic 740 clarifies the accounting for uncertainty in income taxes recognized in an enterprise’s financial statements and prescribes a recognition threshold and measurement attribute for the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return. As of December 31, 2010, the Company had no unrecognized tax benefits. The Company is continuing its practice of recognizing interest and/or penalties related to income tax matters as income tax expense. As of December 31, 2010, the tax years ended December 31, 2006 through December 31, 2009 are open for examination by U.S. taxing authorities.

In assessing its ability to realize deferred tax assets, the Company considers whether it is more likely than not that some portion or all of the deferred tax assets will not be realized. Ultimate realization of deferred tax assets depends on the generation of future taxable income during the periods in which those temporary differences become deductible. The Company considers the scheduled reversal of deferred tax liabilities and projected future taxable income in making this assessment. The Company believes it is more likely than not that it will realize the benefits of these deductible differences.

The provision for income taxes on continuing operations differs from the amounts computed by applying the federal income tax rate of 35% to net income. The differences are summarized as follows:

The Company is insured under a large deductible workers’ compensation insurance policy. The policy generally provides for a $500 deductible per covered accident. The Company maintains letters of credit in the aggregate amount of $11,460 for the benefit of various insurance companies as collateral for retrospective premiums and retained losses which may become payable under the terms of the underlying insurance contracts. The letters of credit are typically renewed annually. No amounts have been drawn under the letters of credit. Accrued expenses at December 31, 2010 and 2009 included approximately $3,695 and $2,458, respectively, for estimated incurred but not reported costs and premium accruals related to our workers’ compensation insurance.

On November 1, 2005, the Company initiated a self-insurance program for major medical, hospitalization and dental coverage for employees and their dependents, which is partially funded by payroll deductions. The Company provided for both reported and incurred but not reported medical costs in the accompanying consolidated balance sheets. We have a maximum liability of $125 per employee/dependent per year. Amounts in excess of the stated maximum are covered under a separate policy provided by an insurance company. Accrued expenses at December 31, 2010 and 2009 included approximately $735 and $784, respectively, for our estimate of incurred but not reported costs related to the self-insurance portion of our health insurance.

During 2009, the Company had 6 operating leases with affiliated entities. As of January 9, 2010, these entities are no longer affiliated entities. Related rent expense was approximately $520 for the year ended December 31, 2009.

The Company had receivables from affiliates of $1,508 and $9,620 at December 31, 2010 and 2009, respectively.

Additional information about our transactions with affiliates is included in Note 2, Equity Method Investments.

The Company leases 14 service locations under noncancelable operating leases that have various expirations from 2011 to 2015. Related rent expense was $986, $1,194, and $1,064 for the years ended December 31, 2010, 2009, and 2008, respectively.

Aggregate future minimum lease payments under the noncancelable operating leases for years subsequent to December 31, 2010 are as follows:

Various claims and lawsuits, incidental to the ordinary course of business, are pending against the Company. In the opinion of management, all matters are adequately covered by insurance or, if not covered, are not expected to have a material effect on the Company’s consolidated financial position, results of operations or cash flows.

On September 21, 2010 through September 23, 2010, the Company sold at auction in separate lots to multiple bidders two complete drilling rigs and components comprising four other drilling rigs (rigs 2, 9, 52, 70, 75 and 94), and ancillary equipment. The drilling rigs and equipment sold at auction were not being utilized currently in the Company’s business. The Company received net proceeds of approximately $8,286, net of selling expenses of $817, for the drilling rigs and related equipment. The Company recorded losses of $19,892 related to the sale of the drilling rigs and ancillary equipment. The loss was based on net book values of approximately $28,178 for the drilling rigs and ancillary equipment. The Company used the entire proceeds to pay down existing indebtedness under its revolving credit facility.

In an unrelated transaction on September 23, 2010, the Company sold two drilling rigs (rigs 41 and 42) in a private sale to Windsor Permian LLC, an unaffiliated third party, for net proceeds of $7,173. The Company recorded a $1,685 loss on the sale of these assets based on a net book value of $8,858.

The decision was made by management in the third quarter to sell an additional five drilling rigs (rigs 5, 6, 7, 51, and 54). Because the drilling rigs meet the held for sale criteria, the Company is required to present such assets, comprised of property and equipment, at the lower of carrying amount or fair value less the anticipated costs to sell. The Company evaluated these assets for impairment as of September 30, 2010 and December 31, 2010, for the year ended 2010, which resulted in recognizing a $7,900 impairment charge. Rig 6 is the only drilling rig unsold at December 31, 2010 with a carrying value of $1,550, which is the anticipated sale price, and is included in Non-current assets held for sale in our Consolidated Balance Sheets. At December 31, 2010, the Company’s fair value estimate was derived from negotiated prices with interested parties. The drilling rigs and related equipment were included as part of our land drilling segment.

On November 17, 2010, the Company sold at auction in separate lots to multiple bidders two complete drilling rigs (rigs 51 & 54) and ancillary equipment. The drilling rigs and equipment sold at auction were not being utilized currently in the Company’s business. The Company received net proceeds of approximately $1,666, net of selling expenses of $115, for the drilling rigs and related equipment. The Company recorded losses of $2,169 related to the sale of the drilling rigs and ancillary equipment. The loss was based on net book values of approximately $3,835 for the drilling rigs and ancillary equipment.

On November 29, 2010, the Company sold two drilling rigs (rigs 5 and 7) and entered into a contract to sell one drilling rig (rig 6) in a private sale to Atlas Drilling, LLC, an unaffiliated third party, for estimated net proceeds of $2,700. The Company recorded a $14 gain on the sale of these assets based on a net book value of $2,686.

The drilling rigs and related equipment sold at auction and the drilling rig held for sale are being sold as part of a broader strategy by management to divest of older drilling rigs and use the proceeds to pay down existing indebtedness.

In the second quarter of 2010, management determined that our well servicing business segment was no longer consistent with the Company’s long-term strategic objectives and that the Company should seek to market this business for sale. During Q1 and Q2 2010 the market for workover services continued at depressed levels within the primary geographic market of our well servicing assets (Oklahoma). Management determined that higher return projects were available within the core drilling segment of the business and chose to deploy capital in this segment rather than commit the capital required to restructure operations in the well servicing segment. In late June management made a decision to market the assets constituting the well servicing segment for sale and redeploy the proceeds to reduce debt and to support the Company’s core drilling business. As of June 30, 2010, the well servicing property and equipment was classified as held for sale in our Consolidated Balance Sheets and well servicing operating results as discontinued operations in our Consolidated Statements of Operations. Well servicing was previously presented as its own reportable segment.

Because the well servicing assets met the held for sale criteria, the Company was required to present such assets, comprised of property and equipment, at the lower of carrying amount or fair value less the anticipated cost to sell. In connection with its June 30, 2010 quarterly report, the Company evaluated well servicing’s respective assets held for sale for impairment. The Company’s analysis as of June 30, 2010 resulted in recognizing a $23,376 impairment charge ($14,329 after tax). This second quarter charge is reflected as a component of loss from discontinued operations in the Company’s Consolidated Statements of Operations for the year ended.

In September 2010, substantially all of the assets of the well servicing segment were sold at auction to multiple bidders. The Company received proceeds of $12,362, net of selling expenses of $638. The sale of the assets of the well servicing segment resulted in a loss of $8,915, which is reflected as a component of loss from discontinued operations in the Company’s Consolidated Statements of Operations. The Company used the proceeds to pay down existing indebtedness under its revolving credit facility. The Company has one workover rig held for sale at December 31, 2010, with a carrying amount of $130. The Company recorded an impairment charge of $318 related to this workover rig during the third quarter.

The results of operations for the years ended December 31, 2010, 2009 and 2008 are below:

At June 30, 2010, the Company’s fair value estimate was derived from an appraisal performed specific to the property and equipment of the Company’s well servicing segment. Refer to Note 12, Fair Value Measurements, for further discussion.

Proceeds from this sale were used to prepay existing indebtedness under our revolving credit facility with Banco Inbursa in July 2010. Based on the proceeds received and net book value of the property and equipment in the amount of $337, the Company recognized a gain of $10,962 in the third quarter of 2010. Operating results and the gain on sale of such assets are included as a component of discontinued operations in our Consolidated Statements of Operations for all periods presented. The trucking assets and operating activities were previously presented as part of our land drilling reportable segment. The results of operations for the years ended December 31, 2010, 2009 and 2008 are below:

The following table presents a reconciliation of the numerators and denominators of the basic and diluted earnings per share (“EPS”) and diluted EPS comparisons as required by ASC Topic 260:

The weighted average number of diluted shares excludes 87,850, 89,108, and 82,962 shares for the years ended December 31, 2010, 2009 and 2008, respectively, subject to restricted stock awards due to their antidilutive effects.

As defined in ASC 820, fair value is defined as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (referred to as an “exit price”). Authoritative guidance on fair value measurements and disclosures clarifies that a fair value measurement for a liability should reflect the entity’s non-performance risk. In addition, a fair value hierarchy is established that prioritizes the inputs to valuation techniques used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted market prices in active markets for identical assets and liabilities (Level 1 measurements) and the lowest priority to unobservable inputs (Level 3 measurements). The three levels of the fair value hierarchy are:

Level 1: Unadjusted quoted prices in active markets that are accessible at the measurement date for identical, unrestricted assets or liabilities.

Level 2: Quoted prices in markets that are not active, or inputs which are observable, either directly or indirectly, for substantially the full term of the asset or liability. This category includes quoted prices for similar assets or liabilities in active markets; quoted prices for identical or similar assets or liabilities in markets that are not active; inputs other than quoted prices that are observable for the asset or liability; and inputs that are derived principally from or corroborated by observable market data by correlation or other means.

Level 3: Measured based on prices or valuation models that require inputs that are both significant to the fair value measurement and less observable from objective sources.

The Company issued a Warrant in conjunction with its revolving credit facility with Banco Inbursa. In accordance with accounting standards, the Company revalued the Warrant as of December 31, 2010 and recorded the change in the fair value of the Warrant on the consolidated statement of operations. The fair value of the Warrant was determined using level 3 inputs. The Company used a pricing model based on a version of the Black Scholes model, which is adjusted to account for the dilution resulting from the additional shares issued for the Warrant. The valuation was determined by computing the value of the Warrant if exercised in Year 1 — 3 with the values weighted by the probability that the Warrant would actually be exercised in that year. Some of the assumptions used in the model were a volatility of 50% and a risk free interest rate that ranged from 0.22% to 0.54%. The fair value of the Warrant was $4,407 at December 31, 2010. The Company recorded a change in the fair value of the Warrant on the consolidated statement of operations in the amount of $(1,578) and $1,850 for the years ended December 31, 2010 and 2009, respectively.

On January 1, 2009, the Company adopted the provisions of ASC 820 for nonfinancial assets and liabilities measured at fair value on a non-recurring basis. Certain assets and liabilities are reported at fair value on a nonrecurring basis in the Company’s consolidated balance sheets. The Company reviews its long-lived assets to be held and used, including property plant and equipment and its investments in Challenger and Bronco MX, whenever events or circumstances indicate that the carrying value of those assets may not be recoverable.

In the second quarter of 2010, management determined that our well servicing business segment was no longer consistent with the Company’s long-term strategic objectives and that the Company should seek to market this business for sale. Because the well servicing property and equipment met the held for sale criteria, the Company was required to present its assets held for sale at the lower of carrying amount or fair value less the anticipated cost to sell. The Company evaluated well servicing’s respective assets held for sale for impairment. The fair value of the well servicing assets was determined using level 3 inputs. The Company engaged a third party independent appraisal company to determine the fair value of the well servicing assets. The appraised value was based on an on-site inspection of the assets and market research and analysis of applicable data. The Company’s analysis as of June 30, 2010 resulted in a $23,376 impairment charge ($14,329 after tax). This charge was recorded in the second quarter of 2010 and is reflected as a component of income (loss) from discontinued operations in the Company’s Consolidated Statements of Operations.

In the third quarter of 2010, management made the decision to divest of older drilling rigs and use the proceeds to pay down existing indebtedness. Consequently, management decided to sell five drilling rigs (rigs 5, 6, 7, 51, and 54). Because the drilling rigs meet the held for sale criteria, the Company is required to present these assets held for sale at the lower of carrying amount or fair value less anticipated cost to sell. The Company evaluated these assets as of September 30, 2010, for impairment. The fair value of the drilling rigs was determined using level 3 inputs. The fair value was determined by the sale price of similar assets sold by the Company in an auction during the third quarter and negotiated prices with interested parties. The analysis as of September 30, 2010 resulted in $7,761 impairment charge. The Company recorded an additional impairment during the fourth quarter of $139.

The Company reviewed its investment in Challenger at December 31, 2010 for impairment due to the recent volatility in oil and natural gas prices, the global economic environment and the anticipated future earnings of Challenger. Fair value of the investment was estimated using a combination of income, or discounted cash flows approach, and the market approach, which utilizes comparable companies’ data. The analysis resulted in a fair value of $40,863 related to our investment in Challenger, which was above the carrying value of the investment and resulted in no impairment. The estimate of fair value required management to make many estimates and judgments, such as forecasts of future cash flows, discount rates of 15.0% and long term growth rates of 3.0% which it believes were reasonable and appropriate at December 31, 2010. Changes in such assumptions can result in an estimate of fair value that could be below the carrying amount of our investments in Challenger.

The Company’s board of directors and a majority of our stockholders approved our 2006 Stock Incentive Plan, which the Company refers to as the 2006 Plan, effective April 20, 2006. Effective December 10, 2010, the Company’s board of directors and a majority of our shareholders approved an amendment to the 2006 Plan to increase the shares available for issuance thereunder by 2,500,000 shares. The purpose of the 2006 Plan is to provide a means by which eligible recipients of awards may be given an opportunity to benefit from increases in value of our common stock through the granting of one or more of the following awards: (1) incentive stock options, (2) nonstatutory stock options, (3) restricted awards, (4) performance awards and (5) stock appreciation rights.

The purpose of the plan is to enable the Company, and any of its affiliates, to attract and retain the services of the types of employees, consultants and directors who will contribute to our long range success and to provide incentives that are linked directly to increases in share value that will inure to the benefit of our stockholders.

Eligible award recipients are employees, consultants and directors of the Company and its affiliates. Incentive stock options may be granted only to our employees. Awards other than incentive stock options may be granted to employees, consultants and directors. The shares that may be issued pursuant to awards consist of our authorized but unissued common stock, and the maximum aggregate amount of such common stock that may be issued upon exercise of all awards under the plan, including incentive stock options, may not exceed 5,000,000 shares, subject to adjustment to reflect certain corporate transactions or changes in our capital structure.

Under all restricted stock awards to date, nonvested shares are subject to forfeiture for failure to fulfill service conditions. Restricted stock awards consist of our common stock that vest over a two year period. Total shares available for future stock option grants and restricted stock grants to employees and directors under existing plans were 2,549,878 at December 31, 2010. Restricted stock awards are valued at the grant date market value of the underlying common stock and are being amortized to operations over the respective vesting period. Compensation expense for the years ended December 31, 2010, 2009 and 2008 related to shares of restricted stock was $3,274, $3,301, and $5,825, respectively. Restricted stock activity for the years ended December 31, 2010, 2009 and 2008 was as follows:

There was $3,863,209 of total unrecognized compensation cost related to nonvested restricted stock awards to be recognized over a weighted-average period of 1.18 years as of December 31, 2010.

Cash and cash equivalents, trade receivables and payables and short-term debt:

The carrying amounts of our cash and cash equivalents, trade receivables, payables and short-term debt approximate their fair values due to the short-term nature of these instruments.

The carrying amount of our long-term debt approximates its fair value, as supported by the recent issuance of the debt and because the rates and terms currently available to us approximate the rates and terms of the existing debt.

The Company implemented a 401(k) retirement plan for its eligible employees during 2008. Under the plan, the Company matches 100% of employees’ contributions up to 5% of eligible compensation. Employee and employer contributions vest immediately. The Company’s contributions for the years ended December 31, 2010, 2009 and 2008 were $548, $628, and $1,093, respectively.

The following table summarizes quarterly unaudited financial data for our years ended December 31, 2010 and 2009:

The Company’s valuation and qualifying accounts for the years ended December 31, 2010, 2009 and 2008 are as follows:

On February 9, 2011, the Company entered into an amendment to its revolving credit facility (the “Amended Credit Facility”) with Banco Inbursa S.A., Institucion de Banca Multiple, Grupo Financiero Inbursa. The Amended Credit Facility reduced the commitment of the lender from $75,000 to $45,000 and reduced the number of drilling rigs pledged as collateral thereunder.

On February 25, 2011, the Company entered into a purchase and sale agreement to sell two drilling rigs (rigs 56 and 62) to Windsor Drilling LLC. The Company expects to record a loss on the sale of the drilling rigs of approximately $1,703 based on estimated proceeds of $11,500 and a net book value of $13,203.

The following pages set forth the unaudited consolidated financial statements of Bronco Drilling Company, Inc. as of March 31, 2011.

The accompanying notes are an integral part of these unaudited consolidated financial statements.

Unless the context requires otherwise, a reference in this quarterly report to “Bronco,” the “Company,” “we,” “us,” and “our” are to Bronco Drilling Company, Inc., a Delaware corporation, and its consolidated subsidiaries.

The Company has prepared the accompanying unaudited consolidated financial statements and related notes in accordance with accounting principles generally accepted in the United States of America for interim financial information and with the instructions of Form 10-Q and Regulation S-X. In preparing the financial statements, the Company made various estimates and assumptions that affect the amounts of assets and liabilities the Company reports as of the dates of the balance sheets and amounts the Company reports for the periods shown in the consolidated statements of operations, stockholders’ equity and cash flows. The Company’s actual results could differ significantly from those estimates. Material estimates that are particularly susceptible to significant changes in the near term relate to the Company’s recognition of revenues and accrued expenses, estimate of the allowance for doubtful accounts, estimate of asset impairments, estimate of deferred taxes and determination of depreciation and amortization expense.

In management’s opinion, the accompanying unaudited consolidated financial statements contain all adjustments (consisting of normal recurring accruals) necessary to present fairly the financial position of the Company as of March 31, 2011, the related results of operations for the three months ended March 31, 2011 and 2010 and the cash flows for the three months ended March 31, 2011 and 2010. The information included in this Quarterly Report on Form 10-Q should be read in conjunction with the Company’s Annual Report on Form 10-K for the year ended December 31, 2010.

The results of operations for the three months ended March 31, 2011 are not necessarily an indication of the results expected for the full year.

A summary of the significant accounting policies consistently applied in the preparation of the accompanying consolidated financial statements follows.

Property and equipment, including renewals and betterments, are capitalized and stated at cost, while maintenance and repairs are expensed currently. Assets are depreciated on a straight-line basis. The depreciable lives of drilling rigs and related equipment are three to 15 years. The depreciable life of other equipment is three years. Depreciation is not commenced until acquired rigs are placed in service. Once placed in service, depreciation continues when rigs are being repaired, refurbished or between periods of deployment. Assets not placed in service and not being depreciated were $20,813 and $14,111 as of March 31, 2011 and December 31, 2010, respectively.

The Company capitalizes interest as a component of the cost of drilling rigs constructed for its own use. For the three months ended March 31, 2011 the Company capitalized $40 of interest expense. The Company did not capitalize any interest for the three months ended March 31, 2010.

The Company evaluates for potential impairment of long-lived assets and intangible assets subject to amortization when indicators of impairment are present, as defined in ASC Topic 360, Accounting for the Impairment or Disposal of Long-Lived Assets. Circumstances that could indicate a potential impairment include significant adverse changes in industry trends, economic climate,

legal factors, and an adverse action or assessment by a regulator. More specifically, significant adverse changes in industry trends include significant declines in revenue rates, utilization rates, oil and natural gas market prices and industry rig counts for drilling rigs and workover rigs. In performing an impairment evaluation, the Company estimated the future undiscounted net cash flows from the use and eventual disposition of long-lived assets and intangible assets grouped at the lowest level that cash flows can be identified. If the sum of the estimated future undiscounted net cash flows is less than the carrying amount of the long-lived assets and intangible assets for these asset grouping levels, then the Company would recognize an impairment charge. The amount of an impairment charge would be measured as the difference between the carrying amount and the fair value of these assets. See Note 7, Asset Sales and Held for Sale, for discussion of impairment of drilling rigs and related equipment due to their classification as held for sale. See Note 8, Discontinued Operations, for discussion of well servicing segment property and equipment impairment relating to its classification as held for sale. The assumptions used in the impairment evaluation for long-lived assets and intangible assets are inherently uncertain and require management judgment.

Pursuant to ASC Topic 740, Income Taxes, the Company follows the asset and liability method of accounting for income taxes, under which the Company recognizes 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. Deferred tax assets and liabilities were measured using enacted tax rates expected to apply to taxable income in the years in which the Company expects to recover or settle those temporary differences. A statutory Federal tax rate of 35% and effective state tax rate of 3.7% (net of Federal income tax effects) were used for the enacted tax rates for all periods.

The Company applies the provisions of ASC Topic 740 which addresses the accounting for uncertainty in income taxes recognized in an enterprise’s financial statements and prescribes a recognition threshold and measurement attribute for the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return. The Company recognizes interest and/or penalties related to income tax matters as income tax expense. As of March 31, 2011, the tax years ended December 31, 2006 through December 31, 2009 are open for examination by U.S. taxing authorities.

Comprehensive income (loss) is comprised of net income (loss) and other comprehensive income. Other comprehensive income includes the translation adjustments of the financial statements of Bronco MX at March 31, 2011. The following table sets forth the components of comprehensive income (loss):

ownership level, which is generally a 20% to 50% interest in the voting securities of the Investee company. Under the equity method of accounting, an Investee company’s accounts are not reflected within the Company’s Consolidated Balance Sheets and Statements of Operations; however, the Company’s share of the earnings or losses of the Investee company is reflected in the caption “Equity in income (loss) of Challenger” and “Equity in income (loss) of Bronco MX” in the Consolidated Statements of Operations. The Company’s carrying value in an equity method Investee company is reflected in the caption “Investment in Challenger” and “Investment in Bronco MX” in the Company’s Consolidated Balance Sheets.

In January 2010, the FASB issued a new accounting standard which requires reporting entities to provide information about movements of assets among Levels 1 and 2 of the three-tier fair value hierarchy established by ASC 820, Fair Value Measurements. Also required is a reconciliation of purchases, sales, issuance, and settlements of financial instruments valued with a Level 3 method, which is used to price the hardest to value instruments. Entities are required to provide fair value measurement disclosures for each class of financial assets and liabilities. The guidance is effective for fiscal years beginning after December 15, 2010. The adoption of this standard did not impact our consolidated financial statements.

On January 4, 2008, we acquired a 25% equity interest in Challenger Limited, or Challenger, in exchange for six drilling rigs and cash. The Company also sold to Challenger four drilling rigs and ancillary equipment. Challenger is an international provider of contract land drilling and workover services to oil and natural gas companies with its principal operations in Libya. The Company also entered into a term note with Challenger related to the sale of four drilling rigs and ancillary equipment. The term note bears interest at 8.5%. Interest and principal payments of $529 on the note are due quarterly until maturity at February 2, 2011. The note receivable is collateralized by the assets sold to Challenger. The note receivable from Challenger at March 31, 2011 and December 31, 2010 was $1,639 and $1,607, respectively.

On February 20, 2008, the Company entered into a Management Services Agreement and Master Services Agreement with Challenger. The Company agreed to make available to Challenger certain employees of the Company for the purpose of providing land drilling services, certain business consulting services and managerial support to Challenger. The Company invoices Challenger monthly for the services provided. The Company had accounts receivable from Challenger of $1,546 and $1,508 at March 31, 2011 and December 31, 2010, respectively, related to these services provided.

Recent civil and political disturbances in Libya have and will continue to affect Challenger’s operations. Ongoing political unrest may result in loss of revenue and damage to Challenger’s equipment. The political turmoil in Libya and elsewhere in North Africa and impact on Challenger’s operations could negatively impact the Company’s investment in Challenger, including the loss of our investment and write off of our receivables from Challenger. Challenger was unable to provide financial statements or other financial information for the three months ended March 31, 2011 due to the events in Libya and disruptions in their operations. Because of the lack of information and uncertainties caused by the events in Libya, we have not recorded or estimated any adjustments to the carrying value of our investment in Challenger, receivable balances or equity in income (loss) of Challenger. We will continue to monitor and evaluate the developments in Libya and our investment in Challenger during 2011 and the Company intends to make required adjustments to equity in income of Challenger in the period that financial statements or other reasonable information are available.

At March 31, 2011 and December 31, 2010, the book value of the Company’s ordinary share investment in Challenger was $38,730. The Company’s 25% interest of the net assets of Challenger was estimated to be $35,428 at December 31, 2010. The basis difference between the Company’s ordinary equity investment in Challenger and the Company’s 25% interest of the net assets of Challenger primarily consists of certain property, plant and equipment and accumulated depreciation in the net amount of $3,626 and $324 at March 31, 2011. These amounts are being amortized against the Company’s 25% interest of Challenger’s net income over the estimated useful lives of 15 years for the property, plant and equipment. Amortization recorded during the three months ended March 31, 2011 and March 31, 2010 was $0 and $61, respectively. The Company recorded equity in loss of investment of $0 and $(599) for the three months ended March 31, 2011 and 2010, respectively, related to its equity investment in Challenger.

Summarized financial information of Challenger is presented below. As described above, we are unable to provide summarized financial information as of and for the three months ended March 31, 2011.

In September, 2009, Carso Infraestructura y Construcción, S.A.B. de C.V., or CICSA, purchased from us 60% of the outstanding membership interests of Bronco MX. Upon closing of the transaction, the Company owned the remaining 40% of the outstanding membership interests of Bronco MX. Immediately prior to the sale of the membership interests in Bronco MX to CICSA, the Company contributed six drilling rigs (Nos. 4, 43, 53, 58, 60 and 72), and the future net profit from rig leases relating to three additional drilling rigs (Nos. 55, 76 and 78), which the Company contributed to Bronco MX upon the expiration of the leases relating to such rigs.

According to a Schedule 13D/A filed with the SEC on April 19, 2011 by Carlos Slim Helú, certain members of his family and affiliated entities (collectively, the “Slim Affiliates”), these individuals and entities collectively own approximately 19.0% of our common stock. CICSA is also a Slim Affiliate.

At March 31, 2011, the book value of the Company’s ordinary share investment in Bronco MX was $21,433. The Company recorded equity in income (loss) of investment of $1 and $(209) for the three months ended March 31, 2011 and March 31, 2010, respectively, related to its equity investment in Bronco MX. The Company’s investment in Bronco MX was increased by $799 as a result of a currency translation gain for the three months ended March 31, 2011.

The credit facility initially provided for revolving advances of up to $75.0 million and the borrowing base under the credit facility was initially set at $75.0 million, subject to borrowing base limitations. On February 9, 2011 we amended our credit

facility which reduced the commitment to $45.0 million. The Company incurred a loss from extinguishment of debt of approximately $1,975 related to the reduction in availability under the credit facility. The credit facility matures on September 17, 2014. Outstanding borrowings under the credit facility bear interest at the Eurodollar rate plus 5.80% per annum, subject to adjustment under certain circumstances. The effective interest rate was 6.51% at March 31, 2011.

The Company pays a quarterly commitment fee of 0.5% per annum on the unused portion of the credit facility and a fee of 1.50% for each letter of credit issued under the facility. In addition, an upfront fee equal to 1.50% of the aggregate commitments under the credit facility was paid by the Company at closing. The Company’s domestic subsidiaries have guaranteed the loans and other obligations under the credit facility. The obligations under the credit facility and the related guarantees are secured by a first priority security interest in substantially all of the assets of the Company and its domestic subsidiaries, including the equity interests of the Company’s direct and indirect subsidiaries. Commitment fees expense for the three months ended March 31, 2011 and 2010 was $50 and $10, respectively.

The credit facility contains customary representations and warranties and various affirmative and negative covenants, including, but not limited to, covenants that restrict the Company’s ability to make capital expenditures, incur indebtedness, incur liens, dispose of property, repay debt, pay dividends, repurchase shares and make certain acquisitions, and a financial covenant requiring that the Company maintain a ratio of consolidated debt to consolidated earnings before interest, taxes, depreciation and amortization as defined in the credit agreement for any four consecutive fiscal quarters of not more than 3.5 to 1.0. The Company was in compliance with all covenants at March 31, 2011. A violation of these covenants or any other covenant in the credit facility could result in a default under the credit facility which would permit the lender to restrict the Company’s ability to access the credit facility and require the immediate repayment of any outstanding advances under the credit facility.

In conjunction with its entry into the credit facility, the Company entered into a Warrant Agreement with Banco Inbursa and, pursuant thereto, issued a three-year warrant (the “Warrant”) to Banco Inbursa evidencing the right to purchase up to 5,440,770 shares of the Company’s common stock, $0.01 par value per share (the “Common Stock”) subject to the terms and conditions set forth in the Warrant, including the limitations on exercise set forth below, at an exercise price of $6.50 per share of Common Stock from the date of issuance of the Warrant (the “Issue Date”) through the first anniversary of the Issue Date, $7.00 per share following the first anniversary of the Issue Date through the second anniversary of the Issue Date, and $7.50 per share following the second anniversary of the Issue Date through the third anniversary of the Issue Date. Banco Inbursa subsequently transferred the Warrant to CICSA.

In accordance with accounting standards, the proceeds from the revolving credit facility were allocated to the credit facility and Warrant based on their respective fair values. Based on this allocation, $50,321 and $4,679 of the net proceeds were allocated to the credit facility and Warrant, respectively. The Warrant has been classified as a liability on the consolidated balance sheet due to the Company’s obligation to pay the seller of the Warrant a make-whole payment, in cash, under certain circumstances. The fair value of the Warrant was determined using a pricing model based on a version of the Black Scholes model, which is adjusted to account for the dilution resulting from the additional shares issued for the Warrant. The valuation was determined by computing the value of the Warrant if exercised in Year 1 — 3 with the values weighted by the probability that the warrant would actually be exercised in that year. Some of the assumptions used in the model were a volatility of 45% and a risk free interest rate that ranged from 0.41% to 1.57%.

The resulting discount to the revolving credit facility is amortized to interest expense over the term of the revolving credit facility. Accordingly, the Company will recognize annual interest expense on the debt at an effective interest rate of Eurodollar rate plus 6.25%. Imputed interest expense recognized for the three months ended March 31, 2011 and 2010 was $229 and $225, respectively.

In accordance with accounting standards, the Company revalued the Warrant as of March 31, 2011 and 2010 and recorded the change in the fair value of the Warrant on the consolidated statement of operations. The fair value of the Warrant was determined using a pricing model based on a version of the Black Scholes model, which is adjusted to account for the dilution resulting from the additional shares issued for the Warrant. The valuation was determined by computing the value of the Warrant if exercised in Year 2 — 3 with the values weighted by the probability that the Warrant would actually be exercised in that year. Some of the assumptions used in the model were volatility between 39% and 49% and a risk free interest rate that ranged from 0.16% to 0.56%. The fair value of the warrant was $14,690 at March 31, 2011. The Company recorded a change in the fair value of the Warrant on the consolidated statement of operations in the amount of $10,283 and $272 for the three months ended March 31, 2011 and 2010, respectively.

The Company is insured under a large deductible workers’ compensation insurance policy. The policy generally provides for a $1,000 deductible per covered accident. The Company maintains letters of credit in the aggregate amount of $8,525 for the benefit of various insurance companies as collateral for retrospective premiums and retained losses which may become payable under the terms of the underlying insurance contracts. The letters of credit are typically renewed annually. No amounts have been drawn under the letters of credit. Accrued expenses at March 31, 2011 and December 31, 2010 included approximately $3,481 and $3,695, respectively, for estimated incurred but not reported costs and premium accruals related to our workers’ compensation insurance.

On November 1, 2005, the Company initiated a self-insurance program for major medical, hospitalization and dental coverage for employees and their dependents, which is partially funded by payroll deductions. The Company provided for both reported and incurred but not reported medical costs in the accompanying consolidated balance sheets. We have a maximum liability of $125 per employee/dependent per year. Amounts in excess of the stated maximum are covered under a separate policy provided by an insurance company. Accrued expenses at March 31, 2011 and December 31, 2010 included approximately $718 and $735, respectively, for our estimate of incurred but not reported costs related to the self-insurance portion of our health insurance.

The Company had receivables from affiliates of $1,546 and $1,508 at March 31, 2011 and December 31, 2010, respectively.

Additional information about our transactions with affiliates is included in Note 2, Equity Method Investments.

Ten putative class action lawsuits relating to the merger agreement and the transactions contemplated therein have been commenced against the Company and current members of our board of directors, including our chief executive officer (the “Individual Defendants”). Six putative class action lawsuits were filed in the District Court of Oklahoma County, Oklahoma (collectively, the “Oklahoma Suits”). Two of the Oklahoma Suits have been voluntarily dismissed. Four putative class action lawsuits were filed in the Court of Chancery of the State of Delaware (the “Delaware Suits” and together with the four remaining Oklahoma Suits, the “Class Actions”). The Delaware Suits were consolidated into a single action on May 6, 2011. The Class Actions each seek certification of a class of all holders of our common stock and variously allege, among other things, that: (1) the Individual Defendants have breached and continue to breach their fiduciary duties to our stockholders; (2) the offer and the merger are unfair to our public stockholders as the proposed transactions underestimate the value of the Company; (3) the Individual Defendants are pursuing a course of conduct that does not maximize the value of the Company; and (4) the Company aided and abetted the alleged breaches of duties by the Individual Defendants. On April 29, 2011, the Delaware Suits were amended, adding allegations that the Schedule 14D-9 filed by the Company and the Schedule TO filed by Chesapeake did not adequately describe the process that resulted in the offer and that the Schedule 14D-9 did not include adequate information concerning the fairness opinion Johnson Rice & Company L.L.C. provided to our board of directors. The Class Actions seek, among other things, an injunction prohibiting consummation of the tender offer and the merger (each as defined below), attorneys’ fees and expenses and rescission or damages in the event the proposed transactions are consummated. We believe the Class Actions are entirely without merit and intend to defend against them vigorously.

On March 21, 2011, the Company sold one complete drilling rig (rig 6) in a private sale to Atlas Drilling, LLC, an unaffiliated third party, for net proceeds of $1,550. The Company recorded a $4 loss on the sale of the assets based on a net book value of $1,554.

On March 31, 2011, the Company sold one complete drilling rig (rig 62) in a private sale to Windsor Drilling, LLC, an unaffiliated third party, for net proceeds of $4,651. The Company recorded a $1,175 loss on the sale of the assets based on a net book value of $5,826.

On February 25, 2011, the Company entered into an agreement with Windsor Drilling, LLC, an unaffiliated third party, to sell an additional drilling rig (rig 56). Because the drilling rig meets the held for sale criteria, the Company is required to present such assets, comprised of property and equipment, at the lower of carrying amount or fair value less the anticipated costs to sell. The Company evaluated these assets for impairment as of March 31, 2011, which resulted in recognizing a $679 impairment charge. The net book value for rig 56 was $7,000 at March 31, 2011 and is included in Non-current assets held for sale and discontinued operations on the consolidated balance sheet.

The sale of drilling rigs and related equipment sold are part of a broader strategy by management to divest of older drilling rigs and use the proceeds to pay down existing indebtedness.

In the second quarter of 2010, management determined that our well servicing business segment was no longer consistent with the Company’s long-term strategic objectives and that the Company should seek to market this business for sale. During Q1 and Q2 2010 the market for workover services continued at depressed levels within the primary geographic market of our well servicing assets (Oklahoma). Management determined that higher return projects were available within the core drilling segment of the business and chose to deploy capital in this segment rather than commit the capital required to restructure operations in the well servicing segment. In 2010 management made a decision to market the assets constituting the well servicing segment for sale and redeploy the proceeds to reduce debt and to support the Company’s core drilling business. Well servicing operating results are included in discontinued operations in our Consolidated Statements of Operations.

The results of operations for the three months ended March 31, 2011 and 2010 are below:

In July 2010, the Company completed the sale of all of the Company’s trucking assets, property and equipment, for $11,299 in cash, net of selling expenses of $403. As drilling activity decreased in 2008 and 2009 the utilization of these trucking assets fell sharply. The ongoing operating losses in our trucking division required resources to be directed away from the core drilling business. As such, management made the decision in the second quarter 2010 to sell these assets as their operations were not considered core. Proceeds from this sale were used to prepay existing indebtedness under our revolving credit facility with Banco Inbursa in July 2010. Operating results are included as a component of discontinued operations in our Consolidated Statements of Operations for all periods presented. The trucking assets and operating activities were previously presented as part of our land drilling reportable segment. The results of operations for the three months ended March 31, 2011 and 2010 are below:

The following table presents a reconciliation of the numerators and denominators of the basic and diluted earnings per share (“EPS”) and diluted EPS comparisons as required by ASC Topic 260:

The weighted average number of diluted shares excludes 464,429 and 55,873 shares for the three months ended March 31, 2011 and 2010, respectively, subject to restricted stock awards due to their antidilutive effects.

Level 1: Unadjusted quoted prices in active markets that are accessible at the measurement date for identical, unrestricted assets or liabilities.

Level 3: Measured based on prices or valuation models that require inputs that are both significant to the fair value measurement and less observable from objective sources.

The Company issued a Warrant in conjunction with its revolving credit facility with Banco Inbursa, which Banco Inbursa subsequently transferred to CICSA. In accordance with accounting standards, the Company revalued the Warrant as of March 31, 2011 and recorded the change in the fair value of the Warrant on the consolidated statement of operations. The fair value of the Warrant was determined using level 3 inputs. The Company used a pricing model based on a version of the Black Scholes model, which is adjusted to account for the dilution resulting from the additional shares issued for the Warrant. The valuation was determined by computing the value of the Warrant if exercised in Year 2 — 3 with the values weighted by the probability that the Warrant would actually be exercised in that year. Some of the assumptions used in the model were volatility of 39% and 49% and a risk free interest rate that ranged from 0.16% to 0.56%. The fair value of the Warrant was $14,690 at March 31, 2011. The Company recorded a change in the fair value of the Warrant on the consolidated statement of operations in the amount of $10,283 and $272 for the three months ended March 31, 2011 and 2010, respectively.

The fair values of our cash equivalents, trade receivables and trade payables approximated their carrying values due to the short-term nature of these instruments.

In the first quarter of 2011, management entered into an agreement to sell one drilling rig (rig 56). Because the drilling rig meets the held for sale criteria, the Company is required to present these assets held for sale at the lower of carrying amount or fair value less anticipated cost to sell. The Company evaluated these assets as of March 31, 2011, for impairment. The fair value of the drilling rig was determined using the agreed upon sales price for the rig. The analysis as of March 31, 2011 resulted in a $679 impairment charge.

Eligible award recipients are employees, consultants and directors of the Company and its affiliates. Incentive stock options may be granted only to our employees. Awards other than incentive stock options may be granted to employees, consultants and directors. The shares that may be issued pursuant to awards consist of our authorized but unissued common stock, and the maximum aggregate amount of such common stock that may be issued upon exercise of all awards under the plan, including incentive stock options, may not exceed 2,500,000 shares, subject to adjustment to reflect certain corporate transactions or changes in our capital structure.

Under all restricted stock awards to date, nonvested shares are subject to forfeiture for failure to fulfill service conditions. Restricted stock awards consist of our common stock that vest over a two or three year period. Total shares available for future stock option grants and restricted stock grants to employees and directors under existing plans were 2,208,272 as of March 31, 2011. Restricted stock awards are valued at the grant date market value of the underlying common stock and are being amortized to operations over the respective vesting period. Compensation expense for the three months ended March 31, 2011 and 2010 was $779 and $395, respectively. Restricted stock activity for the three months ended March 31, 2011 was as follows:

There was $6,642 of total unrecognized compensation cost related to nonvested restricted stock awards to be recognized over a weighted-average period of 1.5 years as of March 31, 2011.

On April 14, 2011, we entered into an Agreement and Plan of Merger with Chesapeake Energy Corporation and Nomac Acquisition, Inc., an indirect wholly owned subsidiary of Chesapeake (“Purchaser”), as previously disclosed on a Form 8-K we filed with the SEC on April 18, 2011. Under the terms of the merger agreement, Chesapeake has agreed to acquire the Company through a two-step transaction, consisting of a tender offer by the Purchaser for all of our outstanding common stock at a price of $11.00 per share without interest thereon and less any applicable withholding or stock transfer taxes, followed by the merger of the Purchaser with and into the Company, with the Company surviving as an indirect, wholly owned subsidiary of Chesapeake. If, after completion of the tender offer, stockholder adoption of the merger agreement is required under Delaware law, we have agreed to hold a meeting of our stockholders for the purpose of adopting the merger agreement. In the Merger, each outstanding share of our common stock, other than shares of our common stock owned by the Company, Chesapeake or Purchaser or their respective wholly owned subsidiaries, or by stockholders who have validly exercised their appraisal rights under Delaware law, will be converted into the right to receive cash in an amount equal to the $11.00 per share offer price, without interest thereon and less any applicable withholding or stock transfer taxes.

Purchaser commenced the tender offer on April 26, 2011. Consummation of the tender offer and the merger is subject to the satisfaction or waiver of a number of customary closing conditions set forth in the merger agreement. We currently expect that the tender offer and merger will be completed during the second quarter of 2011, however, no assurance can be given as to when, or if, the merger will occur.

Each broker-dealer that receives exchange notes in exchange for original notes acquired for its own account as a result of market-making or other trading activities must acknowledge that it will deliver a prospectus in connection with any resale of such exchange notes. By so acknowledging and by delivering a prospectus, a broker-dealer will not be deemed to admit that it is an underwriter within the meaning of the Securities Act of 1933, as amended, which we refer to in this prospectus as the Securities Act. This prospectus, as it may be amended or supplemented from time to time, may be used by broker-dealers in connection with such resales. In addition, until September 11, 2013 (90 days after the date of this prospectus), all dealers effecting transactions in the exchange notes may be required to deliver a prospectus. See “Plan of Distribution.”


FORWARD-LOOKING STATEMENTS			ii
INDUSTRY AND MARKET DATA			iii
PROSPECTUS SUMMARY			1
RISK FACTORS			13
THE EXCHANGE OFFER			28
USE OF PROCEEDS			37
SELECTED HISTORICAL FINANCIAL DATA			38
RATIO OF EARNINGS TO FIXED CHARGES			40
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS			41
BUSINESS			58
MANAGEMENT			69
CORPORATE GOVERNANCE			70
CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS			70
EXECUTIVE COMPENSATION			72
OWNERSHIP OF CHESAPEAKE SECURITIES BY MANAGEMENT			80
DESCRIPTION OF OTHER INDEBTEDNESS			81
DESCRIPTION OF EXCHANGE NOTES			82
BOOK-ENTRY, DELIVERY AND FORM			123
U.S. FEDERAL INCOME TAX CONSIDERATIONS			126
PLAN OF DISTRIBUTION			127
LEGAL MATTERS			128
EXPERTS			128
WHERE YOU CAN FIND MORE INFORMATION			128
INDEX TO FINANCIAL STATEMENTS			F-1


	Three Months Ended March 31,
	2013		2012
	($ in thousands)
Drilling	$	182,729	$	249,791
Hydraulic fracturing		214,946		52,739
Oilfield rentals		47,513		69,073
Oilfield trucking		61,412		44,569
Other operations		37,287		30,709

Total	$	543,887	$	446,881


	Three Months Ended March 31,
	2013		2012
	($ in thousands)
Drilling	$	134,304	$	188,125
Hydraulic fracturing		168,047		36,645
Oilfield rentals		27,616		41,183
Oilfield trucking		51,102		34,892
Other operations		33,980		26,069

Total	$	415,049	$	326,914


	Years Ended December 31,
	2012		2011		2010
	($ in thousands)
Drilling	$	915,208	$	855,023	$	572,325
Hydraulic fracturing		415,168		13,005		—
Oilfield rentals		234,456		245,666		121,411
Oilfield trucking		226,161		127,042		74,281
Other operations		129,029		62,760		47,739

Total	$	1,920,022	$	1,303,496	$	815,756


	Years Ended December 31,
	2012		2011		2010
	($ in thousands)
Drilling	$	668,203	$	685,077	$	483,810
Hydraulic fracturing		303,079		21,787		—
Oilfield rentals		134,075		115,286		78,632
Oilfield trucking		173,327		109,098		60,621
Other operations		112,102		54,991		44,864

Total	$	1,390,786	$	986,239	$	667,927


	Three Months Ended March 31,						Year Ended December 31,
	2013			2012			2012			2011			2010			2009			2008
Ratio of earnings to fixed charges⁽¹⁾		1.9	x		2.6	x		2.2	x		1.6	x		0.7	x		0.2	x		3.7	x
Insufficient coverage	$	—		$	—		$	—		$	—		$	18,887		$	44,296		$	—


	Three Months Ended March 31,				Years Ended December 31,
	(Unaudited)
	(in thousands)
	2013		2012		2012		2011		2010
Adjusted EBITDA	$	108,752	$	104,357	$	439,203	$	277,719	$	120,485


	Payments Due by Period
			Less Than		1-3		4 - 5		More Than
	Total		1 Year		Years		Years		5 Years
	(unaudited) (in thousands)
Long-Term Debt:
6.625% Senior Notes due 2019	$	650,000	$	—	$	—	$	—	$	650,000
Revolving bank credit facility		407,600		—		—		407,600		—
Interest^(a)		301,438		43,063		86,125		86,125		86,125
Purchase obligations^(b)		84,524		84,524		—		—		—
Operating leases^(c)		337,514		84,563		148,257		96,355		8,339

Total	$	1,781,076	$	212,150	$	234,382	$	590,080	$	744,464


	March 31, 2013
	Rigs		Real Property		Rail Cars		Total
	(unaudited)
	(in thousands)
2013	$	67,444	$	12,752	$	4,367	$	84,563
2014		82,478		17,003		5,823		105,304
2015		37,130		—		5,823		42,953
2016		67,514		—		5,823		73,337
2017		20,850		—		2,168		23,018
After 2017		6,172		—		2,167		8,339

Total	$	281,588	$	29,755	$	26,171	$	337,514


	Three Months Ended March 31,						Years Ended December 31,
	2013			2012			2012			2011			2010
Average number of operating rigs for the period		77			111			98			104			83
Average utilization rate		95	%		99	%		92	%		98	%		97	%
Average industry utilization rate		87	%		86	%		86	%		88	%		89	%


Name	Age	Position
Jerry L. Winchester	54	Chief Executive Officer—COO, COF and COS LLC
Cary D. Baetz	48	Chief Financial Officer—COO, COF and COS LLC
James G. (“Jay”) Minmier	49	President—Nomac Drilling, L.L.C.
William R. (“Bill”) Stanger	59	President—Performance Technologies, L.L.C.
Zachary M. (“Zac”) Graves	37	President—Thunder Oilfield Services, L.L.C.
Alan D. (“Al”) Lavenue	52	President—Compass Manufacturing, L.L.C.
Steven C. Dixon	54	Acting Chief Executive Officer and Director—COI; Director—COF
Domenic J. (“Nick”) Dell’Osso, Jr.	36	Executive Vice President, Chief Financial Officer and Director—COI; Director—COF


Name		Position
Jerry L. Winchester^(a)		Chief Executive Officer; Senior Vice President of Chesapeake
Cary D. Baetz^(a)		Chief Financial Officer
Domenic J. (“Nick”) Dell’Osso, Jr^(a)		Chief Financial Officer; Executive Vice President and Chief Financial Officer of Chesapeake


Element	Purpose	Key Characteristics

Base Salary	Reflects each NEO’s base level of responsibility, leadership, tenure, qualifications and contribution to the success and profitability of Chesapeake and the competitive marketplace for executive talent specific to our industry.	Fixed compensation that is reviewed annually and adjusted, if and when appropriate.

Annual Incentive Award	Motivates our NEOs to achieve our short-term business objectives that drive long-term performance while providing flexibility to respond to opportunities and changing market conditions.	Variable performance-based annual cash award. Awards are based on corporate performance compared to pre-established performance goals.

PSU Award	Motivates our NEOs to achieve our business objectives by tying incentives to our financial and key operational metrics over the performance period while continuing to reinforce the link between the interests of our NEOs and our shareholders.	Variable performance-based long-term award. The ultimate number of units earned is based on the achievement of relative and absolute total shareholder return and production and proved reserve growth performance goals.

Restricted Stock Award	Motivates our NEOs to achieve our business objectives by tying incentives to the performance of our common stock over the long term; reinforces the link between the interests of our NEOs and our shareholders; motivates our NEOs to remain with the company by mitigating swings in incentive values during periods of high commodity price volatility.	Long-term restricted stock award with a ratable vesting period over four years. The ultimate value realized varies with our common stock price.

Other Compensation	Provides benefits that promote employee health and work-life balance, which assists in attracting and retaining our NEOs.	Indirect compensation element consisting of health and welfare plans and perquisites.


Name and Principal Position	Year		Salary^(a)		Bonus^(b)		Stock Awards^(c)		Non-Equity Incentive Plan Compensation^(d)		All Other Compensation^(e)		Total
Jerry L. Winchester		2012	$	447,115	$	250,750	$	1,034,450	$	150,000	$	177,059	$	2,059,374
Chief Executive Officer
Cary D. Baetz		2012	$	341,346	$	270,650	$	245,848		—	$	248,384	$	1,106,228
Chief Financial Officer


Name	Type of Award^(a)	Grant Date		Approval Date^(b)	Number of Shares of Restricted Stock^(c)		Estimated Future Payouts Under Non-Equity Incentive Plan Awards^(d) Threshold / Target / Maximum	Estimated Future Payouts Under Equity Incentive Plan Awards^(e) Threshold / Target / Maximum	Grant Date Fair Value^(f)
Jerry L. Winchester	AIP		—	—		—	$250,000 / $500,000 / 1,000,000	—		—
	RS		Jan 3, 2012	Dec 29, 2011		8,475	—	—	$	200,010
	RS		July 2, 2012	June 21, 2012		32,035	—	—	$	600,016
	PSU		Jan 3, 2012	Dec 15, 2011		—	—	1,059 / 8,475 / 21,188	$	234,424
Cary D. Baetz	RS		Feb 29, 2012	Feb 29, 2012		100	—	—	$	2,500
	RS		Feb 29, 2012	Feb 29, 2012		4,733	—	—	$	118,325
	RS		July 2, 2012	June 21, 2012		6,675	—	—	$	125,023


	Stock Awards
Name	Number of Shares of Stock That Have Not Vested^(a)		Market Value of Shares of Stock That Have Not Vested^(b)		Equity Incentive Plan Awards: Number of Unearned Units That Have Not Vested^(c)		Equity Incentive Plan Awards: Value of Unearned Units That Have Not Vested^(b)(d)
Jerry L. Winchester		47,923	$	796,480		8,210	$	139,406
Cary D. Baetz		11,508	$	191,263		—		—


Name	Executive Contribution in Last Fiscal Year^(a)		Company Contribution in Last Fiscal Year^(b)		Aggregate Earnings in Last Fiscal Year			Aggregate Withdrawals / Distributions		Aggregate Balance at Last Fiscal Year-End^(c)
Jerry L. Winchester	$	107,067	$	82,067	$	(3,331	)	$	—	$	185,803
Cary D. Baetz	$	—	$	—	$	—		$	—	$	—


Executive Benefits and Payments Upon Separation	Termination without Cause		Change of Control		Incapacity of Executive		Death of Executive
Compensation:
Cash Severance	$	500,000	$	1,500,000	$	250,000	$	500,000
Acceleration of Equity-based Compensation:
Restricted Stock Awards	$	796,480	$	796,480	$	796,480	$	796,480
PSU Awards^(a)	$	139,406	$	143,906	$	139,406	$	139,406
401(k) Plan and DCP Matching	$	74,440	$	74,440	$	88,320	$	88,320

Total	$	1,510,326	$	2,514,826	$	1,274,206	$	1,524,206


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^(a)		222		—		222
Cary D. Baetz^(a)		2		—		2
All executive officers as a group		224		—		224


Year	Percentage
2015		103.313	%
2016		101.656	%
2017 and thereafter		100.000	%


		Page
CHESAPEAKE OILFIELD OPERATING, L.L.C. AUDITED CONSOLIDATED FINANCIAL STATEMENTS:

Report of independent registered public accounting firm		F-2
Consolidated balance sheets at December 31, 2012 and 2011		F-3
Consolidated statements of operations for the years ended December 31, 2012, 2011 and 2010		F-4
Consolidated statements of changes in equity for the years ended December 31, 2012, 2011 and 2010		F-5
Consolidated statements of cash flows for the years ended December 31, 2012, 2011 and 2010		F-6
Notes to Consolidated Financial Statements		F-7

CHESAPEAKE OILFIELD OPERATING, L.L.C. UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS:

Condensed consolidated balance sheets at March 31, 2013 and December 31, 2012		F-40
Condensed consolidated statements of operations for the three months ended March 31, 2013 and 2012		F-41
Condensed consolidated statements of changes in equity for the three months ended March 31, 2013		F-42
Condensed consolidated statements of cash flows for the three months ended March 31, 2013 and 2012		F-43
Notes to Condensed Consolidated Financial Statements		F-44

BRONCO DRILLING COMPANY, INC. AUDITED CONSOLIDATED FINANCIAL STATEMENTS:

Report of independent registered public accounting firm		F-64
Consolidated balance sheets at December 31, 2010 and 2009		F-65
Consolidated statements of operations for the years ended December 31, 2010, 2009 and 2008		F-66
Consolidated statements of stockholders’ equity and comprehensive income (loss) for the years ended December 31, 2010, 2009 and 2008		F-67
Consolidated statements of cash flows for the years ended December 31, 2010, 2009 and 2008		F-68
Notes to Consolidated Financial Statements		F-70

BRONCO DRILLING COMPANY, INC. UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS:

Unaudited consolidated balance sheets at March 31, 2011 and December 31, 2010		F-90
Unaudited consolidated statements of operations for the three months ended March 31, 2011 and 2010		F-91
Unaudited consolidated statement of stockholders’ equity and comprehensive income (loss) for the three months ended March 31, 2011		F-92
Unaudited consolidated statements of cash flows for the three months ended March 31, 2011 and 2010		F-93
Notes to Consolidated Financial Statements		F-94


	December 31,
	2012				2011
	($ in thousands)
Assets:
Current Assets:
Cash		$	1,227		$	530
Accounts receivable, net of allowance of $496 and $102 at December 31, 2012 and 2011, respectively			25,910			31,070
Affiliate accounts receivable			337,705			172,456
Inventory			52,228			26,693
Deferred income tax asset			3,305			3,535
Prepaid expenses and other			24,484			16,891

Total Current Assets			444,859			251,175

Property and Equipment:
Property and equipment, at cost			2,096,150			1,608,747
Less: accumulated depreciation			(541,117	)		(362,290	)
Property and equipment held for sale, net			26,486			1,360

Total Property and Equipment, Net			1,581,519			1,247,817

Other Assets:
Investments			18,216			16,657
Goodwill			42,447			42,572
Intangible assets, net			11,382			15,336
Deferred financing costs, net			16,741			19,644
Other long-term assets			4,347			3,935

Total Other Assets			93,133			98,144

Total Assets		$	2,119,511		$	1,597,136

Liabilities and Equity:
Current Liabilities:
Accounts payable		$	28,810		$	39,695
Affiliate accounts payable			31,592			36,395
Accrued liabilities			228,342			163,754

Total Current Liabilities			288,744			239,844

Long-Term Liabilities:
Deferred income tax liabilities			149,932			104,160
Senior notes			650,000			650,000
Revolving credit facility			418,200			29,000
Other liabilities			15,818			25,236

Total Long-Term Liabilities			1,233,950			808,396

Commitments and Contingencies (Note 7)
Owner’s Equity			596,817			548,896

Total Liabilities and Equity		$	2,119,511		$	1,597,136


	Years Ended December 31,
	2012			2011			2010
	($ in thousands)
Revenues:
Revenues from Chesapeake	$	1,811,253		$	1,226,420		$	779,290
Revenues from third parties		108,769			77,076			36,466

Total Revenues		1,920,022			1,303,496			815,756
Operating Expenses:
Operating costs		1,390,786			986,239			667,927
Depreciation and amortization		231,322			175,790			103,339
General and administrative, including expenses from affiliates (Notes 1 and 14)		66,360			37,074			25,312
Losses (gains) on sales of property and equipment		2,025			(3,571	)		(854	)
Impairments and other		60,710			2,729			9

Total Operating Expenses		1,751,203			1,198,261			795,733

Operating Income		168,819			105,235			20,023

Other Income (Expense):
Interest expense, including expenses from affiliates (Note 5)		(53,548	)		(48,802	)		(38,795	)
Losses from equity investees		(361	)		—			(2,243	)
Other income (expense)		1,543			(2,464	)		211

Total Other Expense		(52,366	)		(51,266	)		(40,827	)

Income (Loss) Before Income Taxes		116,453			53,969			(20,804	)
Income Tax Expense (Benefit)		46,877			26,279			(4,195	)

Net Income (Loss)		69,576			27,690			(16,609	)

Less: Net Loss Attributable To Noncontrolling Interest		—			(154	)		(639	)

Net Income (Loss) Attributable To Chesapeake Oilfield Operating, L.L.C.	$	69,576		$	27,844		$	(15,970	)


	Owner’s Equity			Noncontrolling Interest			Total Equity
	($ in thousands)
Balance at January 1, 2010	$	180,736		$	—		$	180,736
Net loss		(15,970	)		(639	)		(16,609	)
Distributions to owner, net		(4,659	)		—			(4,659	)
Noncontrolling interest		—			5,092			5,092

Balance at December 31, 2010		160,107			4,453			164,560
Net income (loss)		27,844			(154	)		27,690
Acquisition of noncontrolling interest		—			(4,299	)		(4,299	)
Contributions from owner, net		360,945			—			360,945

Balance at December 31, 2011		548,896			—			548,896
Net income		69,576			—			69,576
Distributions to owner, net		(21,655	)		—			(21,655	)

Balance at December 31, 2012	$	596,817		$	—		$	596,817


							Estimated
	December 31,						Useful
	2012			2011			Life
	($ in thousands)						(in years)
Drilling rigs and related equipment	$	988,968		$	893,466			3-15
Hydraulic fracturing equipment		342,930			105,621			5
Oilfield rental equipment		332,066			289,652			2-10
Trucking and fluid disposal equipment		210,472			141,979			5-8
Leasehold improvements		140,111			105,249			3-5
Vehicles		61,814			56,782			3
Buildings and improvements		2,195			1,416			3-39
Land		440			440			—
Other		17,154			14,142			3-7

Total property and equipment, at cost		2,096,150			1,608,747
Less: accumulated depreciation and amortization		(541,117	)		(362,290	)
Property and equipment held for sale, net		26,486			1,360

Total property and equipment, net	$	1,581,519		$	1,247,817


	December 31, 2012
	($ in thousands)
2013		$	3,953
2014			2,009
2015			620
2016			480
2017			480
After 2017			3,840

Total		$	11,382


	As of June 6, 2011
	($ in thousands)
Current assets	$	53,396
Drilling rigs and equipment		290,932
Goodwill		27,434
Intangible assets		10,000
Other		15,461

Total assets acquired		397,223
Current liabilities		31,542
Long-term liabilities		1,223
Deferred income taxes		25,258

Total liabilities assumed		58,023

Net assets acquired	$	339,200


Year	Redemption Price
2015		103.313	%
2016		101.656	%
2017 and thereafter		100.000	%


	December 31, 2012
	Rigs		Real Property		Rail Cars		Total
	($ in thousands)
2013	$	92,731	$	15,845	$	5,886	$	114,462
2014		82,482		15,845		5,823		104,150
2015		37,134		—		5,823		42,957
2016		67,516		—		5,823		73,339
2017		20,850		—		2,168		23,018
After 2017		6,172		—		2,167		8,339

Total	$	306,885	$	31,690	$	27,690	$	366,265


	Number of Unvested Restricted Shares			Weighted Average Grant-Date Fair Value
	(in thousands)
Unvested shares as of January 1, 2012		1,496		$	27.15
Granted		1,170		$	20.70
Vested		(537	)	$	27.69
Forfeited		(289	)	$	24.55

Unvested shares as of December 31, 2012		1,840		$	23.27

Unvested shares as of January 1, 2011		1,268		$	26.89
Granted		939		$	29.18
Vested		(611	)	$	29.99
Forfeited		(100	)	$	26.51

Unvested shares as of December 31, 2011		1,496		$	27.15

Unvested shares as of January 1, 2010		994		$	30.03
Granted		674		$	23.75
Vested		(257	)	$	30.59
Forfeited		(143	)	$	27.26

Unvested shares as of December 31, 2010		1,268		$	26.89


	December 31, 2012				December 31, 2011
	Carrying Amount		Fair Value (Level 2)		Carrying Amount		Fair Value (Level 2)
	($ in thousands)
Financial liabilities:
Credit Facility	$	418,200	$	401,000	$	29,000	$	29,000
2019 Senior Notes	$	650,000	$	614,250	$	650,000	$	665,847


	Drilling			Hydraulic Fracturing			Oilfield Rentals			Oilfield Trucking			Other Operations			Intercompany Eliminations			Consolidated Total
	($ in thousands)
For The Year Ended December 31, 2012:
Revenues	$	921,378		$	419,692		$	235,743		$	232,067		$	141,733		$	(30,591	)	$	1,920,022
Intersegment revenues		(6,170	)		(4,524	)		(1,287	)		(5,906	)		(12,704	)		30,591			—

Total revenues	$	915,208		$	415,168		$	234,456		$	226,161		$	129,029		$	—		$	1,920,022
Depreciation and amortization		117,756			26,491			62,762			23,523			790			—			231,322
(Gains) losses on sales of property and equipment		5,526			43			(3,579	)		35			—			—			2,025
Impairments and other		53,621			—			6,929			—			160			—			60,710
Interest expense		—			—			—			—			(53,548	)		—			(53,548	)
(Losses) income from equity investees		—			139			—			(500	)		—			—			(361	)
Other income (expense)		1,061			152			87			(6	)		249			—			1,543
Income (Loss) Before Income Taxes	$	44,167		$	82,623		$	27,133		$	24,013		$	(61,483	)	$	—		$	116,453
Total Assets	$	1,113,856		$	452,206		$	254,983		$	236,580		$	71,282		$	(9,396	)	$	2,119,511
Capital Expenditures	$	237,672		$	237,483		$	85,729		$	61,063		$	878		$	—		$	622,825
For The Year Ended December 31, 2011:
Revenues	$	855,023		$	13,005		$	247,336		$	130,858		$	62,760		$	(5,486	)	$	1,303,496
Intersegment revenues		—			—			(1,670	)		(3,816	)		—			5,486			—

Total revenues	$	855,023		$	13,005		$	245,666		$	127,042		$	62,760		$	—		$	1,303,496
Depreciation and amortization		110,064			1,210			49,200			14,882			1,204			(770	)		175,790
(Gains) losses on sales of property and equipment		(2,438	)		—			(761	)		(377	)		5			—			(3,571	)
Impairments and other		68			—			2,633			28			—			—			2,729
Interest expense		(25,709	)		(2,134	)		(7,802	)		(3,952	)		(9,205	)		—			(48,802	)
Other income (expense)		(3,060	)		1			(6	)		227			374			—			(2,464	)
Income (Loss) Before Income Taxes	$	12,428		$	(12,551	)	$	66,961		$	(4,501	)	$	(8,368	)	$	—		$	53,969
Total Assets	$	995,229		$	138,341		$	258,960		$	150,896		$	55,034		$	(1,324	)	$	1,597,136
Capital Expenditures	$	171,936		$	86,985		$	88,351		$	61,057		$	4,424		$	—		$	412,753


	Parent		Guarantor Subsidiaries			Eliminations			Consolidated
Assets:
Current Assets:
Cash	$	863	$	364		$			$	1,227
Accounts receivable		—		25,910			—			25,910
Affiliate accounts receivable		3,636		337,573			(3,504	)		337,705
Inventory		—		52,228			—			52,228
Deferred income tax asset		—		3,305			—			3,305
Prepaid expenses and other		381		24,103			—			24,484

Total Current Assets		4,880		443,483			(3,504	)		444,859

Property and Equipment:
Property and equipment, at cost		—		2,096,150			—			2,096,150
Less: accumulated depreciation		—		(541,117	)		—			(541,117	)
Property and equipment held for sale, net		—		26,486			—			26,486

Total Property and Equipment, Net		—		1,581,519			—			1,581,519

Other Assets:
Investments		—		18,216			—			18,216
Goodwill		—		42,447			—			42,447
Intangible assets, net		—		11,382			—			11,382
Deferred financing costs, net		16,741		—			—			16,741
Other long-term assets		29,566		4,347			(29,566	)		4,347
Investments in subsidiaries and intercompany advances		1,624,572		—			(1,624,572	)		—

Total Other Assets		1,670,879		76,392			(1,654,138	)		93,133



Total Assets	$	1,675,759	$	2,101,394		$	(1,657,642	)	$	2,119,511

Liabilities and Equity:
Current Liabilities:
Accounts payable	$	418	$	28,392		$	—		$	28,810
Affiliate accounts payable		717		34,379			(3,504	)		31,592
Accrued liabilities		9,607		218,735			—			228,342

Total Current Liabilities		10,742		281,506			(3,504	)		288,744

Long-Term Liabilities:
Deferred income tax liabilities		—		179,498			(29,566	)		149,932
Senior notes		650,000		—			—			650,000
Revolving credit facility		418,200		—			—			418,200
Other liabilities		—		15,818			—			15,818

Total Long-Term Liabilities		1,068,200		195,316			(29,566	)		1,233,950

Equity		596,817		1,624,572			(1,624,572	)		596,817

Total Liabilities and Equity	$	1,675,759	$	2,101,394		$	(1,657,642	)	$	2,119,511


	Parent			Guarantor Subsidiaries			Eliminations			Consolidated
Revenues:
Revenues	$	4,756		$	1,919,797		$	(4,531	)	$	1,920,022
Operating Expenses:
Operating costs		6,587			1,390,474			(6,275	)		1,390,786
Depreciation and amortization		—			231,322			—			231,322
General and administrative		19,531			46,829			—			66,360
Losses on sales of property and equipment		—			2,025			—			2,025
Impairments and other		—			60,710			—			60,710

Total Operating Expenses		26,118			1,731,360			(6,275	)		1,751,203

Operating Income (Loss)		(21,362	)		188,437			1,744			168,819

Other Income (Expense):
Interest expense		(53,546	)		(2	)		—			(53,548	)
Loss from equity investees		—			(361	)		—			(361	)
Other income		2			1,541			—			1,543
Equity in net earnings of subsidiary		114,950			—			(114,950	)		—

Total Other Income (Expense)		61,406			1,178			(114,950	)		(52,366	)

Income (Loss) Before Income Taxes		40,044			189,615			(113,206	)		116,453
Income Tax Expense (Benefit)		(27,788	)		74,665			—			46,877

Net Income (Loss)		67,832			114,950			(113,206	)		69,576

Less: Net Loss Attributable to Noncontrolling Interest		—			—			—			—

Net Income (Loss) Attributable to Chesapeake Oilfield Operating, L.L.C.	$	67,832		$	114,950		$	(113,206	)	$	69,576


	March 31, 2013			December 31, 2012
	($ in thousands)
Assets:
Current Assets:
Cash	$	1,745		$	1,227
Accounts receivable, net of allowance of $489 and $496 at March 31, 2013 and December 31, 2012, respectively		23,153			25,910
Affiliate accounts receivable		423,865			337,705
Inventory		51,811			52,228
Deferred income tax asset		4,880			3,305
Prepaid expenses and other		23,376			24,484

Total Current Assets		528,830			444,859

Property and Equipment:
Property and equipment, at cost		2,180,898			2,096,150
Less: accumulated depreciation		(604,743	)		(541,117	)
Property and equipment held for sale, net		—			26,486

Total Property and Equipment, Net		1,576,155			1,581,519

Other Assets:
Investments		18,271			18,216
Goodwill		42,447			42,447
Intangible assets, net		10,394			11,382
Deferred financing costs		16,015			16,741
Other long-term assets		4,485			4,347

Total Other Assets		91,612			93,133

Total Assets	$	2,196,597		$	2,119,511

Liabilities and Equity:
Current Liabilities:
Accounts payable	$	53,063		$	28,810
Affiliate accounts payable		40,911			31,592
Other current liabilities		271,217			228,342

Total Current Liabilities		365,191			288,744

Long-Term Liabilities:
Deferred income tax liabilities		161,289			149,932
Senior notes		650,000			650,000
Revolving credit facility		407,600			418,200
Other long-term liabilities		14,428			15,818

Total Long-Term Liabilities		1,233,317			1,233,950

Commitments and Contingencies (Note 4)
Owner’s Equity		598,089			596,817

Total Liabilities and Equity	$	2,196,597		$	2,119,511