10-K 1 coo-20131231x10k.htm 10-K COO-2013.12.31-10K
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549

Form 10-K

ý
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
FOR THE FISCAL YEAR ENDED DECEMBER 31, 2013
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TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
FOR THE TRANSITION PERIOD FROM                      TO                     

Commission File No. 333-187766
 
Chesapeake Oilfield Operating, L.L.C.

(Exact name of registrant as specified in its charter) 
Oklahoma
 
45-3338422
(State or other jurisdiction of
incorporation or organization)
 
(I.R.S. Employer
Identification No.)
 
 
 
6100 North Western Avenue
Oklahoma City, Oklahoma
 
73118
(Address of principal executive offices)
 
(Zip Code)
(405) 848-8000
(Registrant’s telephone number, including area code)

Securities registered pursuant to Section 12(b) of the Act:
None

Securities registered pursuant to Section 12(g) of the Act:
None

Chesapeake Oilfield Operating, L.L.C. meets the conditions set forth in General Instruction (I)(1)(a) and (b) of Form 10-K and is therefore filing this Form 10-K with the reduced disclosure format.

Indicate by check mark whether the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.    Yes  ¨    No  ý

Indicate by check mark whether the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.    Yes  ¨    No  ý

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.    Yes  ý    No  ¨

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).    Yes  ý    No  ¨

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein and will not be contained, to the best of the registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.    ý

Indicate by check mark whether the registrant is a large accelerated filer, accelerated filer, non-accelerated filer, or smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.
Large accelerated filer
 
¨
 
Accelerated filer
 
¨
 
 
 
 
 
 
 
Non-accelerated filer
 
ý  (Do not check if a smaller reporting company)
 
Smaller reporting company
 
¨

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).    Yes  ¨    No  ý

The aggregate market value of the common equity held by non-affiliates as of June 30, 2013: None


TABLE OF CONTENTS
 
 
 
Page
Item 1.
Item 1A.
Item 1B.
Item 2.
Item 3.
Item 4.
 
 
Item 5.
Item 6.
Item 7.
Item 7A.
Item 8.
Item 9.
Item 9A.
Item 9B.
 
 
 
 
Item 10.
Item 11.
Item 12.
Item 13.
Item 14.
 
 
 
Item 15.
 
 




We meet the conditions specified in General Instruction I(1)(a) and (b) of Form 10-K and are thereby permitted to use the reduced disclosure format for wholly owned subsidiaries of reporting companies specified therein. Accordingly, we have omitted from this report the information called for by Item 6 (Selected Financial Data), Item 10 (Directors, Executive Officers and Corporate Governance), Item 11 (Executive Compensation) and Item 12 (Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters) of Form 10-K.

Forward-Looking Statements

Certain statements contained in this report 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,” “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. We caution you not to place undue reliance on the forward-looking statements contained in this report, which speak only as of the filing date.

Our actual results could differ materially from those anticipated in these forward-looking statements as a result of many factors, including the following factors:

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dependence on Chesapeake Energy Corporation ("Chesapeake") and its working interest partners for a majority of our revenues and our ability to secure new customers or provide additional services to existing customers;

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our customers' expenditures for oilfield services;

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the limitations that Chesapeake’s and our own level of indebtedness may have on our financial flexibility and restrictions in our or Chesapeake's debt agreements;

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the cyclical nature of the oil and natural gas industry;

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market prices for oil and natural gas;

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

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our and Chesapeake's credit profile;

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access to and cost of capital;

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

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increased labor costs or the unavailability of skilled workers;

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competitive conditions;

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legislative or regulatory changes, including changes in environmental regulations, drilling regulations and liability under federal and state environmental laws and regulations; and

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the factors generally described in Item 1A - Risk Factors in this report.

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. We caution you not to place undue reliance on the forward-looking statements contained in this report, which speak only as of the filing date. Except as may be required by law, we do not intend, and do not assume any obligation, to update any forward-looking statements.



PART I

Item 1.
Business

We are a diversified oilfield services company that provides a wide range of wellsite services and equipment to U.S. land-based exploration and production ("E&P") customers operating in unconventional resource plays. We offer services and equipment that are strategic to our customers’ oil and natural gas operations. Our services include drilling, hydraulic fracturing, oilfield rentals, rig relocation and fluid handling and disposal. Our operations are geographically diversified across many of the most active oil and natural gas plays in the onshore United States, including the Anadarko and Permian Basins and the Barnett, Eagle Ford, Haynesville, Marcellus, Niobrara and Utica Shales.
Our Operating Segments

Drilling

Drilling rig fleet.. Our drilling segment provides land drilling and drilling-related services, including directional drilling, geosteering and mudlogging, for oil and natural gas E&P activities. As of March 1, 2014, we owned or leased a fleet of 115 land drilling rigs. The following table depicts the geographic areas in which our drilling segment operated as of March 1, 2014, including the number of active rigs contracted by Chesapeake and third parties in each geographic area and the total number of active rigs in each geographic area according to Baker Hughes.
 
 
Rigs Contracted by
 
 
 
 
Geographic Area
 
Chesapeake
 
Third Parties
 
Total COO Rigs
 
Total Active Rigs in Area
Anadarko Basin
 
13
 
13
 
26
 
172
Eagle Ford Shale
 
16
 
2
 
18
 
222
Utica Shale
 
7
 
5*
 
12
 
42
Marcellus Shale
 
6
 
2
 
8
 
77
Niobrara Shale
 
2
 
2
 
4
 
54
Haynesville Shale
 
7
 
—
 
7
 
44
Permian Basin
 
—
 
4
 
4
 
506
      Total
 
51
 
28
 
79
 
1,117
* Excludes six proprietary PeakeRigs™ being built, all of which are under contract with third parties and expected to be delivered by March 2015.

We continue to modernize our asset base and have a fleet of 10 proprietary PeakeRigs™. We are scheduled to receive six additional PeakeRigs™ by March 2015. 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 existing PeakeRigs™ and future new-build rigs will include top drives, iron roughnecks, walking systems and mechanized catwalks.
 
In addition to the enhancements we have made to our drilling rigs, we also have ancillary assets and personnel to provide an integrated drilling service for the customer. We provide integrated directional drilling and mud logging services in conventional and horizontal applications.

Drilling customers and contracts. For the years ended December 31, 2012 and 2013, we derived 91% and 80% of our drilling revenues from Chesapeake and 9% and 20% from third parties, respectively. Our customers, as operators of the wells that we service, engage us and pay 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. These contracts provide for drilling services on a well-by-well basis or for a term of a certain number of days or a certain number of wells. The specific terms of each request for other services are typically set forth in a field ticket or purchase or work order. As of December 31, 2013, all of our drilling contracts were 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,

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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.

Hydraulic Fracturing

Hydraulic fracturing services. Our hydraulic fracturing segment provides high-pressure hydraulic fracturing (or frac) services and other well stimulation services. 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. As of March 1, 2014, we owned nine hydraulic fracturing fleets with an aggregate of 360,000 horsepower and all nine of these fleets were contracted by Chesapeake in the Anadarko Basin and the Eagle Ford and Utica Shales.

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.

We purchase the fracturing fluid additives 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. In addition to performing internal vendor environmental and operational quality control at the well site, 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. We contract with Chesapeake pursuant to a master services agreement (the "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 terms such as the estimated number of fracturing stages to be performed, pricing, quantities of products required, with horsepower and pressure ratings of the hydraulic fracturing fleets to be used. We are compensated based on the number of fracturing stages we complete and pricing is market-based.

Oilfield Rentals

Our oilfield rentals segment provides premium rental tools and services for land-based oil and natural gas drilling, completion and workover activities. We offer an extensive line of rental tools, including drill-pipe, drill collars and tubing. Additionally, we offer surface rental equipment including blowout preventers, frac tanks, mud tanks and environmental containment that leverage all phases of the hydrocarbon extraction and production process. We also provide frac-support services, including rental and rig-up/rig-down of wellhead pressure control equipment (frac stacks), delivery of on-site frac water through a water transfer operation and monitoring and controlling of production returns through our testing and flowback business. As of March 1, 2014, we offered oilfield rental services in the Anadarko and Permian Basins and the Eagle Ford, Haynesville, Marcellus, Niobrara and Utica Shales.


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Oilfield Trucking

Our oilfield trucking segment provides drilling rig relocation and logistics services as well as fluid handling services. As of March 1, 2014, we owned a fleet of 260 rig relocation trucks and 67 cranes and forklifts and operated in the Marcellus Shale, Eagle Ford Shale and Utica Shale. As of March 1, 2014, we owned a fleet of 247 fluid handling trucks, which were operating in the Anadarko and Permian Basins and the Barnett, Eagle Ford, Haynesville, Marcellus and Utica Shales.

Customers and Competition

The markets in which we operate are highly competitive. Chesapeake and our other customers pay us market-based rates for the services 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 and our other customers less for such products and services.

We are currently a party to the Master Services Agreement with Chesapeake, pursuant to which we provide drilling and other services and supply materials and equipment to Chesapeake and we are a party to a services agreement (the "Services Agreement") with Chesapeake under which Chesapeake agreed to guarantee the utilization of a portion of our drilling rig and hydraulic fracturing fleets during the term of the agreement. 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. Under the Services 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 reduction for each of our drilling rigs that is operated by a third-party customer. If Chesapeake does not meet its rig commitment, it is required to pay us a non-utilization fee. For each day that a committed rig was not operated, Chesapeake was required to 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 recorded $2.4 million in revenues for non-utilization fees pursuant to the Services Agreement for the year ended December 31, 2013. We did not record any revenues for non-utilization for the years ended December 31, 2012 and 2011.

Under the Services Agreement, 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 reduction for each stage that we perform for a third-party customer during such month. If Chesapeake does meet its stage commitment, it is 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 years ended December 31, 2013, 2012 and 2011.

Competitors in each of our operating segments will include:

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

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Hydraulic Fracturing - Halliburton Company, Schlumberger Limited, Baker Hughes Incorporated, FTS International, Inc., C&J Energy Services, Inc. and several other competitors with national, regional or local hydraulic fracturing operations.

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

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

Suppliers

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


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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. We have entered into non-metallic mineral mining leases at sand mining sites in Wisconsin and we expect to complete construction on a frac sand facility by 2016.

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.

Employees

At every level of our operations, our employees are critical to our success and committed to operational excellence. Our senior management team has extensive experience building, acquiring and managing oilfield 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, 2013, we employed approximately 5,300 people. None of these employees is covered by collective bargaining agreements, and we and Chesapeake consider our relationships with our employees to be good.

Risk Management and Insurance

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

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 $460.0 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 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.


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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. Please read “Risk Factors-Risks Relating to Our Industry and Our Business-Oilfield anti-indemnity provisions enacted by many states may restrict or prohibit a party’s indemnification of us.”

Safety and Maintenance

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

Regulation of Operations

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 Industry and 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.

Environmental Matters

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

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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, including Naturally Occurring Radioactive Material, or NORM, 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. Among other things, these final rules require the reduction of volatile organic compound emissions from natural gas wells through the use of reduced emission completions or “green completions” on all hydraulically fractured wells constructed or refractured after January 1, 2015. In addition, gas wells are required to use completion combustion device equipment (i.e., flaring) by October 15, 2012 if emissions cannot be directed to a gathering line. Further, the final rules under NESHAP include maximum achievable control technology (MACT) standards for “small” glycol dehydrators that are located at major sources of hazardous air pollutants and modifications to the leak detection standards for valves. At the industry’s urging, the EPA has amended portions of these rules in 2013 and continues to evaluate additional changes. 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.

The Federal Water Pollution Control Act (Clean Water Act) and resulting regulations, which are primarily implemented through a system of permits, also govern the discharge of certain contaminants into waters of the United States. Sanctions for failure to comply strictly with the Clean Water Act are generally resolved by payment of fines and correction of any identified deficiencies. However, regulatory agencies could require us to cease construction or operation of certain facilities or to cease hauling wastewaters to facilities owned by others that are the source of water discharges. In addition, the Federal Oil Pollution Act of 1990 (OPA) and resulting regulations impose a variety of obligations on responsible parties related to the prevention of oil spills and liability for damages resulting from such spills in waters of the United States. The term “waters of the United States” has been broadly defined to include inland water bodies, including wetlands and intermittent streams. The OPA assigns joint and several strict liability to each responsible party for oil removal costs and a variety of public and private damages. The OPA also imposes ongoing requirements on a responsible party, including the preparation of oil spill response plans and proof of financial responsibility to cover environmental cleanup and restoration costs that could be incurred in connection with an oil spill.

The Safe Drinking Water Act (SDWA) and comparable local and state provisions restrict the disposal, treatment or release of water produced or used during oil and gas development. Subsurface emplacement of fluids (including disposal wells or enhanced oil recovery) is governed by federal or state regulatory authorities that, in some cases, includes the state oil and gas regulatory authority or the state’s environmental authority. These regulations may increase the costs of compliance for some facilities.


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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. Please read “Risk Factors-Risks Relating to Our Industry and Our Business.”

Hydraulic Fracturing. Vast quantities of oil, natural gas liquids and natural gas deposits exist in deep shale 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

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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.

Cyclical Nature of Industry

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

Item 1A.
Risk Factors

Risks Relating to Our Industry and Our Business

We are dependent on Chesapeake for a significant portion 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 is favorable to us.

We currently provide substantially all of our oilfield services and equipment to Chesapeake and its working interest partners although revenues derived from third party E&P customers have recently increased. For the years ended December 31, 2011, 2012 and 2013, Chesapeake and its working interest partners accounted for approximately 94%, 94% and 90% of our revenues, respectively. If Chesapeake ceases to engage us on terms that are attractive to us during such period, our business, financial condition and results of operations would be materially adversely affected. Accordingly, we are indirectly subject to the business and financial risks of Chesapeake, some of which are the following:

•
the volatility of oil and natural gas prices, which could have a negative effect on the value of Chesapeake’s oil and natural gas properties, its drilling program, its ability to finance its operations and its willingness to allocate capital toward exploration and development activities;

•
the availability of capital on favorable terms to fund its exploration and development activities;


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

•
uncertainties inherent in estimating quantities of natural gas and oil reserves and projecting future rates of production;

•
its drilling and operating risks, including potential environmental liabilities;

•
pipeline, storage and other transportation capacity constraints and interruptions;

•
adverse effects of governmental and environmental regulation; and

•
losses from pending or future litigation.

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 for 2014, it is projecting that its capital expenditures will approximate its cash flow from operations. If Chesapeake is unable to generate cash flow from operations sufficient to fund its capital expenditures, Chesapeake may be required to reduce its spending on drilling and completion activities, which could have a material adverse impact on our business, financial condition and results of operations.

We serve customers who are involved in drilling for and producing oil and natural gas. Adverse developments affecting the oil and natural gas industry or drilling activity, including sustained low natural gas prices, a decline in oil or natural gas liquids prices, reduced demand for oil and natural gas products and increased regulation of drilling and production, could have a material adverse effect on our business, financial condition and results of operations.
    
Our revenues are primarily generated from customers who are engaged in drilling for and producing oil and natural gas. Developments that adversely affect oil and natural gas drilling and production services could adversely affect our customers’ demand for our products and services, resulting in a material adverse effect on our business, financial condition and results of operations.
    
The predominant factor that would reduce demand for our products and services is reduced land-based drilling activity in the continental United States. Commodity prices, and market expectations of potential changes in these prices, may significantly affect this level of activity, as well as the rates paid for our services. Natural gas prices declined significantly in late 2011 and 2012 to the lowest level in recent years, and while prices have risen in recent months from their lows recently given the harsh winter, they remain depressed as compared to historical levels. For example, the twelve-month average New York Mercantile Exchange (NYMEX) price of natural gas futures contracts per MMBtu was $4.17, $3.54 and $3.24 as of December 31, 2013, 2012 and 2011, respectively. Oil prices have fluctuated significantly in recent years, reaching record highs in 2008, dropping below $40 per barrel in 2009 and trading on the NYMEX at a WTI spot price of $101.12 per barrel as of March 10, 2014. We negotiate the rates payable under our contracts based on prevailing market prices. Declines in the price of natural gas, as well as declines in the prices of oil or natural gas liquids, could have an adverse impact on the level of drilling, exploration and production activity, which could materially and adversely affect the demand for our products and services and our results of operations. However, higher commodity prices do not necessarily translate into increased drilling activity because our customers' expectations of future prices also influences their activity. Additionally, 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 liquids-rich plays that are currently more economical. We have incurred costs and had downtime in the past as we redeployed equipment and personnel from dry natural gas plays to liquids-rich plays and may in the future incur redeployment costs and have downtime any time our customers' activities are refocused towards different drilling regions.  
    
Another factor that would reduce demand for our products and services is a decline in the level of drilling and production activity as a result of increased government regulation of that activity. Our customers’ drilling and production operations are subject to extensive federal, state, local and foreign laws and government regulations concerning emissions of pollutants and greenhouse gases; hydraulic fracturing; the handling of oil and natural gas and byproducts thereof and other materials and substances used in connection with oil and natural gas operations, including drilling fluids and wastewater; well spacing; production limitations; plugging and abandonment of wells; unitization and pooling of properties; and taxation. More stringent legislation or regulation, a moratorium on drilling or hydraulic fracturing, or increased taxation of oil and natural gas drilling

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activity could directly curtail such activity or increase the cost of drilling, resulting in reduced levels of drilling activity and therefore reduced demand for our products and services.

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 cyclical.

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:

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

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

•
the availability, pricing and perceived safety of pipeline, trucking, train storage and other transportation capacity;

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

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

•
the discovery rates of new oil and natural gas reserves;

•
laws and regulations relating to environmental matters;

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

•
adverse weather conditions, including hurricanes that can affect oil and natural gas operations over a wide area;

•
oil refining capacity;

•
merger and divestiture activity among oil and gas producers;

•
tax laws, regulation and policies;

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

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

•
the political environment in oil and natural gas producing regions, including uncertainty or instability resulting from civil disorder, terrorism or war;

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

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

•
uncertainty in capital and commodities markets; and

•
the ability of oil and natural gas producers to raise capital on favorable terms.

Anticipated future prices for natural gas and crude oil are a primary factor affecting spending and drilling activity by E&P companies, including Chesapeake. Actual or anticipated 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.    

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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. Our drilling and service contracts provide 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.    

As a result of relatively lower natural gas prices in recent years, many E&P companies, including Chesapeake, reduced drilling in plays characterized by higher concentrations of dry natural gas. Although many of these companies, including Chesapeake, 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 any time our customers’ activities are refocused towards different drilling regions.

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 an impact on our business, even in a stronger oil and natural gas price environment. An adverse development in any of these areas could have an adverse impact on our customers’ operations or financial condition, which could in turn result in reduced demand for our products and services.

Our industry is highly competitive. If we are unable to compete successfully, our profitability may be reduced.

The market for oilfield services in which we operate is highly competitive. Price competition, rig or fleet availability, location and suitability, experience of the workforce, safety records, reputation, operating integrity and condition of the equipment are all factors used by customers in awarding contracts. Our future success and profitability will partly depend upon our ability to keep pace with our customers' demands with respect to these factors. Our competitors are numerous, ranging from terminal companies and major oil companies to other independent marketers and distributors of varying sizes, financial resources and experience. Some of our competitors may have greater financial, technical and personnel resources than us. 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 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, any increase in the supply of land drilling rigs and hydraulic fracturing fleets could have a material adverse impact on market prices under our contracts and utilization rates of our services. This increased supply could also require higher capital investment to keep our services competitive.

Our business involves many hazards and operational risks, and we are not insured against all the risks we face.

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

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

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

•
pollution and other damage to the environment;

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

•
fires and explosions;

•
mechanical or technological failures;

•
spillage handling and disposing of materials;

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•
adverse weather conditions; and

•
failure of our employees to comply with our internal environmental health and safety guidelines.

If any of these hazards occur, they could result in suspension of operations, termination of contracts without compensation, 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 and results of operations. 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.”

Our business may be adversely affected by a deterioration in general economic conditions or a weakening of the broader energy industry.
    
A prolonged economic slowdown, another recession in the United States, adverse events relating to the energy industry and local, regional and national economic conditions and factors, particularly a slowdown in the E&P industry, could negatively impact our operations and therefore adversely affect our results. The risks associated with our business are more acute during periods of economic slowdown or recession because such periods may be accompanied by decreased spending by our customers.

Restrictions in the agreements governing our outstanding indebtedness could adversely affect our business, financial condition and results of operations.

The operating and financial restrictions in our Credit Facility and in the Indenture governing our outstanding 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, our Credit Facility and the Indenture limit our and our subsidiaries’ ability to, among other things:

•
incur additional debt or issue guarantees;

•
incur or permit certain liens to exist;

•
make certain investments, acquisitions or other restricted payments;

•
dispose of assets;

•
engage in certain types of transactions with affiliates;

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

•
prepay certain indebtedness.

Furthermore, our Credit Facility contains covenants requiring us to maintain a maximum consolidated leverage ratio and a minimum fixed charge coverage ratio.

A failure to comply with the covenants in the 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

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

We are highly leveraged and may incur additional debt in the future.

As of December 31, 2013, we had $1.055 billion of indebtedness, comprised of $650.0 million of senior notes and $405.0 million of borrowings outstanding under our Credit Facility.

Our level of indebtedness will have several important effects on our future operations, including, without limitation:

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

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

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

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

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 of the foregoing could have a material adverse effect on our business, financial condition and results of operations.

Our assets may require significant amounts of capital for maintenance, upgrades and refurbishment.

Our drilling rigs and hydraulic fracturing fleets may require significant capital investment in maintenance, upgrades and refurbishment to maintain the competitiveness of our assets. Our rigs and fleets typically do not generate revenue while they are undergoing maintenance, refurbishment or upgrades. Any maintenance, upgrade or refurbishment project for our assets could increase our indebtedness or reduce cash available for other opportunities. Further, such projects may require proportionally greater capital investments as a percentage of total asset value, which may make such projects difficult to finance on acceptable terms. To the extent we are unable to fund such projects, we may have fewer rigs and fleets available for service or our rigs and fleets may not be attractive to potential or current customers. Such demands on our capital or reductions in demand for our rigs and fleets could have a material adverse effect on our business, financial condition and results of operations.

We participate in a capital intensive industry and we may not be able to finance our capital needs.

We intend to rely primarily on cash flows from operating activities and borrowings under our revolving bank credit facilty ("Credit Facility"). If our cash flows from operating activities and borrowings under our Credit Facility are not sufficient to fund our capital expenditures budget, we would be required to fund these expenditures through the issuance of debt or equity or alternative financing plans, such as:
 
•
refinancing or restructuring our debt;

•
selling assets; or

•
reducing or delaying acquisitions or capital investments, such as planned upgrades or acquisitions of equipment and refurbishments of our rigs and related equipment, even if previously publicly announced.

The terms of existing or future debt instruments may restrict us from adopting some of these alternatives. 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 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,

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which could further restrict our business operations. Moreover, our separation from Chesapeake could lead to a deterioration of our credit profile, could increase our costs of borrowing money and limit our access to the capital markets and commercial credit.

We may need to obtain additional capital or financing to fund expansion of our asset base, which could increase our financial leverage.
    
In order to expand our asset base, we will need to make growth capital expenditures. These expenditures may be significant because our assets require significant capital to purchase and modify. If we do not make sufficient or effective expansion capital expenditures, we will be unable to expand our business operations and may be required to use cash from our operations or incur borrowings or sell common stock or other securities in order to fund our expansion capital expenditures. Our ability to obtain financing or to access the capital markets for future equity or debt offerings may be limited by our financial condition at the time of any such financing or offering as well as the covenants in our debt agreements, general economic conditions and contingencies and uncertainties that are beyond our control. In addition, incurring additional debt may significantly increase our interest expense and financial leverage, and issuing common stock may result in significant dilution to our current shareholders.

We may not be successful in identifying and making acquisitions.

Part of our strategy to grow our business is dependent on our ability to make acquisitions that result in an increase in revenues and customer contracts. We may be unable to make accretive acquisitions or realize expected benefits of any acquisitions for any of the following reasons:

•
failure to identify attractive targets in the marketplace;

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

•
failure to obtain acceptable financing;

•
restrictions in our debt agreements;

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

•
failure to retain or attract key employees; and

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

Our acquisition strategy requires that we successfully integrate acquired companies into our business practices as well as our procurement, management and enterprise-wide information technology systems. We may not be successful in implementing our business practices at acquired companies, and our acquisitions could face difficulty in transitioning from their previous information technology systems to our own. Any such difficulties, or increased costs associated with such integration, could affect our financial performance and operations.

If we are unable to identify, complete and integrate acquisitions, it could have a material adverse effect on our growth strategy, business, financial condition and results of operations.


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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 and results of operations.

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. During the twelve months ended December 31, 2013, based on total purchase cost, our three largest suppliers of raw materials and finished products represented 55% of such purchases. 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 and results of operations.  

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

We are dependent upon the efforts and skills of our executives to 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 and results of operations.

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 and results of operations.


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We may record losses or impairment charges related to idle assets or assets that we sell.

Prolonged periods of low utilization, changes in technology or the sale of assets below their carrying value may cause us to experience losses. These events could result in the recognition of impairment charges that reduce our net income. For example, for the years ended December 31, 2013 and 2012, we recognized $23.6 million and $11.8 million, respectively, of impairment charges for certain drilling rigs and spare equipment we had identified to sell as part of our broader strategy to divest of non-essential drilling rigs; and for the years ended December 31, 2013 and 2012, we recognized impairment charges of $25.4 million and $14.9 million, respectively, related to certain drilling rigs that we deemed to be impaired based on our assessment of future demand and the suitability of the identified rigs in light of this demand. Please read Note 3 to the audited consolidated financial statements included elsewhere in this report. Significant impairment charges as a result of a decline in market conditions or otherwise could have a material adverse effect on our financial condition.

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 and results of operations.  

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

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

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

We typically enter into agreements with our customers governing the provision of our services, which 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 Louisiana, New Mexico, Texas 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 and results of operations.

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 any major changes may have a material adverse effect on our business, financial condition and results of operations.


16

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 and results of operations.

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 handling 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 and results of operations.

Changes in laws or government regulations regarding hydraulic fracturing could increase our costs of doing business, limit the areas in which our customers can operate and reduce oil and natural gas production by our customers, which could adversely impact our business.
    
Hydraulic fracturing involves the injection of water, sand or an alternative proppant and chemicals under pressure into target geological formations to fracture the surrounding rock and stimulate production. Recently, there has been increased public concern regarding an alleged potential for hydraulic fracturing to adversely affect drinking water supplies, and proposals have been made to enact separate federal, state and local legislation that would increase the regulatory burden imposed on hydraulic fracturing. Congress has in recent legislative sessions considered legislation to amend the Safe Water Drinking Act (the “SDWA”), including legislation that would repeal the exemption for hydraulic fracturing from the definition of “underground injection” and require federal permitting and regulatory control of hydraulic fracturing, as well as legislative proposals to require disclosure of the chemical constituents of the fluids used in the fracturing process, were proposed in recent sessions of Congress. The U.S. Congress may consider similar SDWA legislation in the future.
    
In addition, EPA has asserted federal regulatory authority pursuant to the SDWA over certain hydraulic fracturing activities involving the use of diesel fuels and published permitting guidance on February 11, 2014 addressing the performance of such activities using diesel fuels in those states where EPA is the permitting authority. Also, in November 2011, the EPA announced its intent to develop and issue regulations under the Toxic Substances Control Act to require companies to disclose information regarding the chemicals used in hydraulic fracturing and the agency currently plans to issue a Notice of Proposed Rulemaking in August 2014 that would seek public input on the design and scope of such disclosure regulations. Further, on October 21, 2011, the EPA announced its intention to propose federal Clean Water Act regulations by 2014 governing wastewater discharges from hydraulic fracturing and certain other natural gas operations. In addition, the U.S. Department of the Interior published a revised proposed rule on May 16, 2013 that would update existing regulation of hydraulic fracturing activities on federal lands, including requirements for disclosure, well bore integrity and handling of flowback water. The revised proposed rule was subject to an extended 90-day public comment period, which ended on August 23, 2013.

17

    
Presently, hydraulic fracturing is regulated primarily at the state level, typically by state oil and natural gas commissions and similar agencies. Several states where we conduct our water and environmental services business, such as Texas and Pennsylvania, have either adopted or proposed laws and/or regulations to require oil and natural gas operators to disclose chemical ingredients and water volumes used to hydraulically fracture wells, in addition to more stringent well construction and monitoring requirements. The chemical ingredient information is generally available to the public via online databases, and this may bring more public scrutiny to hydraulic fracturing operations.
    
The EPA is conducting a study of the potential impacts of hydraulic fracturing activities on drinking water. The EPA issued a Progress Report in December 2012 and a draft final report is anticipated by 2014 for peer review and public comment. As part of this study, the EPA requested that certain companies provide them with information concerning the chemicals used in the hydraulic fracturing process. This study or other studies may be undertaken by the EPA or other governmental authorities, depending on their results, could spur initiatives to regulate hydraulic fracturing under the SDWA or otherwise. If new federal, state or local laws or regulations that significantly restrict hydraulic fracturing are adopted, such legal requirements could result in delays, eliminate certain drilling activities and make it more difficult or costly for us to perform fracturing. Any such regulations limiting or prohibiting hydraulic fracturing could reduce oil and natural gas exploration and production activities by our customers and, therefore, adversely affect our business. Such laws or regulations could also materially increase our costs of compliance and doing business by more strictly regulating how hydraulic fracturing wastes are handled or disposed.

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 and results of operations.

We and our customers 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 and our customers’ 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 nevertheless 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 and results of operations. Additionally, an increase in regulatory requirements on oil and gas exploration and completion activities could significantly delay or interrupt our operations.

In response to certain scientific studies suggesting that emissions of greenhouse gases, or GHGs, including carbon dioxide and methane, are contributing to the warming of the Earth’s atmosphere and other climatic conditions, the U.S. Congress has considered adopting legislation to reduce emissions of GHGs, and almost one-half of the states have already taken legal measures to reduce emissions of GHGs, primarily through the planned development of GHG emission inventories and/or regional GHG cap-and-trade programs. In addition, in December 2009, the EPA determined that emissions of carbon dioxide, methane and certain other GHGs endanger public health and the environment because emissions of such gases are, according to the EPA, contributing to warming of the earth’s atmosphere and other climatic changes. Based on these findings, the EPA has begun adopting and implementing regulations to restrict emissions of GHGs under existing provisions of the Clean Air Act (CAA). The EPA has already adopted two sets of rules regulating GHG emissions under the CAA, one of which requires a reduction in emissions of GHGs from motor vehicles and the other of which regulates emissions of GHGs from certain large stationary sources, both of which became effective in January 2011. The EPA’s rules relating to emissions of GHGs from large stationary sources of emissions are currently subject to a number of legal challenges, but the federal courts have thus far declined to issue any injunctions to prevent the EPA from implementing or requiring state environmental agencies to implement the rules. The EPA has also adopted rules requiring the monitoring and reporting of GHG emissions from specified GHG

18

emission sources in the U.S., including oil and natural gas exploration and production operations, on an annual basis. Although it is not possible at this time to estimate how potential future laws or regulations addressing GHG emissions would impact our business, either directly or indirectly, any future federal, state or local laws or implementing regulations that may be adopted to address GHG emissions in areas where we operate could require us or our customers to incur increased compliance and operating costs. Regulation of GHGs could also result in a reduction in demand for and production of oil and natural gas, which would result in a decrease in demand for our services. Additionally, to the extent that such unfavorable weather conditions are exacerbated by global climate change or otherwise, our operations may be adversely affected to a greater degree than we have previously experienced, including increased delays and costs. We cannot predict with any certainty at this time how these possibilities may affect our operations, but effects could be materially adverse. 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 always 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.

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

Adverse weather can directly impede our operations. Repercussions of severe weather conditions may include:
 
•
curtailment of services;

•
weather-related damage to facilities and equipment, resulting in suspension of operations;
 
•
inability to deliver equipment and personnel to job sites in accordance with contract schedules; and

•
loss of productivity.

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.

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.

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 Industry and Our Business—We are dependent on Chesapeake for a significant portion 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.”


19

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 2019 Senior 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 Item 13 of this report 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 Credit Facility and indenture governing the 6.625% senior notes due 2019 (the "2019 Senior Notes") 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, although the 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 2019 Senior Notes and, because we are wholly-owned, such holders do not indirectly benefit from fiduciary duties that Chesapeake would owe to a minority owner. As a result, holders of the 2019 Senior 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 Item 13 of this report 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. Although Chesapeake has agreed 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 Item 13 of this report 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.

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

Under our facilities lease agreement with Chesapeake, in return for the use of certain yards and other physical facilities from 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.

20


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 Item 13 of this report for a more complete description of certain of our agreements with Chesapeake.

Item 1B.
Unresolved Staff Comments
 
 
 

None.

Item 2.
Properties
 
 
 

We conduct our operations out of a number of field offices, yards, shops, terminals and other facilities principally located in Ohio, Oklahoma, Pennsylvania, Texas, West Virginia and Wyoming. Each of these facilities is currently 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.

Item 3.
Legal Proceedings
 
 
 

We are subject to various legal proceedings and claims arising in the ordinary course of our business. Our management does not expect the outcome of any of these known legal proceedings, individually or collectively, to have a material adverse effect on our financial condition or results of operations.
 
Item 4.
Mine Safety Disclosures
 
 
 

Not applicable.

21

PART II. OTHER INFORMATION
 
Item 5.
Market for Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities.

All of our common stock is owned by Chesapeake and is not traded on any stock exchange.

No dividends were paid during the years ended December 31, 2013, 2012 and 2011.

Our 2019 Senior Notes and Credit Facility restrict our ability to distribute dividends.

Item 6.
Selected Financial Data

The information called for by Item 6 is omitted pursuant to Instruction I(2) to Form 10-K (Omission of Information by Certain Wholly Owned Subsidiaries).

22


Item 7.
Management’s Discussion and Analysis of Financial Condition and Results of Operations
 
 
 

Overview

Oilfield services companies provide services and equipment that are used by E&P companies in connection with the exploration for, and the development and production of, hydrocarbons. We are a diversified oilfield services company that provides a wide range of wellsite services to U.S. land-based E&P customers operating in unconventional resource plays. We offer services and equipment that are strategic to our customers’ oil and natural gas operations. Our services include drilling, hydraulic fracturing, oilfield rentals, rig relocation and fluid handling and disposal. Our operations are geographically diversified across many of the most active oil and natural gas plays in the onshore United States, including the Anadarko and Permian Basins and the Barnett, Eagle Ford, Haynesville, Marcellus, Niobrara and Utica Shales.

Since we commenced operations in 2001, we have actively grown our business and modernized our asset base. As of March 1, 2014, we owned 81 land drilling rigs including 10 proprietary PeakeRigs™ that utilize advanced electronic drilling technology and leased 34 land drilling rigs. As of March 1, 2014, we also owned (a) nine hydraulic fracturing fleets with an aggregate of 360,000 horsepower; (b) a diversified oilfield rentals business; and (c) an oilfield trucking fleet consisting of 260 rig relocation trucks, 67 cranes and forklifts used in the movement of drilling rigs and other heavy equipment and 247 fluid handling trucks. We continue to modernize our asset base and are building 6 additional PeakeRigs™.

Recent Developments

On February 24, 2014, Chesapeake announced that it was pursuing strategic alternatives for COO, including a potential spin-off to Chesapeake shareholders or an outright sale.

How We Generate Our Revenues

We currently derive a substantial majority of our revenues from providing oilfield services and equipment to Chesapeake and its working interest partners. 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. Pursuant to our Master Services Agreement with Chesapeake, we provide drilling and other services and supply 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 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 we provide Chesapeake are market-based. A brief description of the ways in which we are compensated for the services we provide appears below.

Drilling Segment. As of December 31, 2013, all of our drilling contracts were rig-specific daywork contracts. A rig-specific 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 between locations, 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 the Services 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 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 is required to pay us a non-utilization fee. For each day that a committed rig is not operated, Chesapeake is required to 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 is no assurance that any such non-utilization fee would equal or exceed the amount of revenues we could generate or the margins we could realize through normal operations. We recorded $2.4 million in revenues for non-utilization fees pursuant to the agreement for the year ended December 31, 2013. We did not record any revenues for non-utilization 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

23

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 the Services Agreement, 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 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 is required to pay us a non-utilization fee equal to $40,000 for each committed stage not performed; however, there is no assurance that any such non-utilization fee would 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 years ended December 31, 2013, 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 handling services. We price these services by the hours and volume and recognize revenue as services are performed.

Other Operations. We derive substantially all of our revenues from other operations from our natural gas compression unit and related oil and gas production equipment manufacturing business.  

The Costs of Conducting Our Business

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

We have an administrative services agreement (the "Administrative Services Agreement") with Chesapeake pursuant to which Chesapeake allocates certain expenses to us. Under the Administrative Services Agreement, in return for the general and administrative services provided by Chesapeake, we have historically reimbursed 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 performed 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.

Liquidity and Capital Resources

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 Credit Facility, access to capital markets and other financing transactions. We believe we will have adequate liquidity over the next twelve months to operate our business and to meet our cash requirements.

Our $500.0 million Credit Facility is an important source of liquidity for us. 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 agreement. As of December 31, 2013, the Credit Facility was not subject to any such limitations and had borrowing availability of approximately $95.0 million. We are allowed to request increases in the total commitments under the Credit Facility by up to $400.0 million in the aggregate, in part or in full, at any time during the term of the Credit Facility, with any such increases being subject to

24

compliance with the restrictive covenants in the Credit Facility and in the indenture governing our 2019 Senior Notes, as well as lender approval. The Credit Facility matures on November 3, 2016.

Historically, we have provided substantially all of our oilfield services to Chesapeake and its working interest partners. During the years ended December 31, 2013, 2012 and 2011, Chesapeake and its working interest partners accounted for approximately 90%, 94% and 94% of our revenues, respectively.

Capital Expenditures

Total capital expenditures, including maintenance, were $349.8 million, $622.8 million and $412.8 million for the years ended December 31, 2013, 2012 and 2011, respectively. We currently expect our growth capital expenditures to be approximately $100.0 million for 2014, and we expect these expenditures to grow our business lines, particularly our drilling rig fleet. We may increase, decrease or re-allocate our anticipated capital expenditures during any period based on industry conditions, the availability of capital or other factors, and we believe that a significant component of our anticipated capital spending is discretionary.

Cash Flow

Our cash flow depends on the level of spending by Chesapeake, its working interest partners and our third-party customers on 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 flow for the years ended December 31, 2013, 2012 and 2011.
 
 
Years Ended December 31,
 
2013
 
2012
 
2011
 
(in thousands)
Cash Flow Statement Data:
 
 
 
 
 
Net cash provided by operating activities
$
337,071

 
$
211,151

 
$
240,046

Net cash used in investing activities
$
(296,817
)
 
$
(577,324
)
 
$
(658,470
)
Net cash (used in) provided by financing activities
$
(39,803
)
 
$
366,870

 
$
418,584

Cash, beginning of period
$
1,227

 
$
530

 
$
370

Cash, end of period
$
1,678

 
$
1,227

 
$
530


Operating Activities. Cash provided by operating activities was $337.1 million, $211.2 million and $240.0 million for the years ended December 31, 2013, 2012 and 2011, respectively. Changes in working capital items increased (decreased) cash flow provided by operating activities by $36.7 million, ($168.7) million and $6.1 million for the years ended December 31, 2013, 2012 and 2011, 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.

Investing Activities. Cash used in investing activities was $296.8 million, $577.3 million and $658.5 million for the years ended December 31, 2013, 2012 and 2011, respectively. Capital expenditures are the main component of our investing activities. The majority of our capital expenditures for the years ended December 31, 2013, 2012 and 2011 were related to our investment in new hydraulic fracturing equipment and PeakeRigs™ and the purchase of certain leased drilling rigs. We purchased 23 leased drilling rigs for approximately $140.2 million during 2013 and 25 leased drilling rigs for approximately $36.2 million in 2012. Cash used in investing activities was partially offset by proceeds from asset sales in the amounts of $50.6 million, $47.4 million and $110.9 million for the years ended December 31, 2013, 2012 and 2011, respectively.

In November 2011, we acquired Horizon Oilfield Services, L.L.C. ("Horizon") for $17.5 million. In June 2011, we acquired Bronco Drilling Company, Inc. ("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 $0.4 million, $1.9 million and $16.7 million in the years ended December 31, 2013, 2012 and 2011, respectively. On October 7, 2011, we entered into an agreement to acquire 49% of the membership

25

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. During 2013, we sold our membership interest in Big Star and received cash proceeds of approximately $2.8 million.

Financing Activities. Net cash (used in) provided by financing activities was ($39.8) million, $366.9 million and $418.6 million for the years ended December 31, 2013, 2012 and 2011, respectively. On November 3, 2011, we entered into a five-year $500.0 million senior secured credit facility. We had borrowings and repayments under our Credit Facility of $1.217 billion and $1.230 billion, respectively, during 2013. We had borrowings and repayments under our Credit Facility of $1.389 billion and $999.9 million, respectively, during 2012. We had borrowings and repayments under our 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 2019 Senior Notes. 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 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, 2013, 2012 and 2011 our (distributions to) contributions from our owner were ($29.9) million, ($22.3) million and $453.2 million, respectively.

Results of Operations

Years Ended December 31, 2013, 2012 and 2011

The following table sets forth our consolidated statements of operations for the years ended December 31, 2013, 2012 and 2011.
 
 
Years Ended December 31,
 
 
2013
 
2012
 
2011
 
 
(in thousands)
 
Revenues:
 
 
 
 
 
 
Revenues from Chesapeake
$
1,960,256

 
$
1,811,253

 
$
1,226,420

 
Revenues from third parties
227,949

 
108,769

 
77,076

 
Total Revenues
2,188,205

 
1,920,022

 
1,303,496

 
Operating Expenses:
 
 
 
 
 
 
Operating costs
1,717,709

 
1,390,786

 
986,239

 
Depreciation and amortization
289,591

 
231,322

 
175,790

 
General and administrative, including expenses from affiliates
80,354

 
66,360

 
37,074

 
(Gains) losses on sales of property and equipment
(2,629
)
 
2,025

 
(3,571
)
 
Impairments and other
74,762

 
60,710

 
2,729

 
Total Operating Expenses
2,159,787

 
1,751,203

 
1,198,261

 
Operating Income
28,418

 
168,819

 
105,235

 
Other Income (Expense):
 
 
 
 
 
 
Interest expense
(56,786
)
 
(53,548
)
 
(48,802
)
 
Loss from equity investees
(958
)
 
(361
)
 
—

 
Other income (loss)
1,758

 
1,543

 
(2,464
)
 
Total Other Expense
(55,986
)
 
(52,366
)
 
(51,266
)
 
(Loss) Income Before Income Taxes
(27,568
)
 
116,453

 
53,969

 
Income Tax (Benefit) Expense
(7,833
)
 
46,877

 
26,279

 
Net (Loss) Income
(19,735
)
 
69,576

 
27,690

 
Less: Net Loss Attributable to Noncontrolling Interest
—

 
—

 
(154
)
 
Net (Loss) Income Attributable to Chesapeake Oilfield Operating, L.L.C.
$
(19,735
)
 
$
69,576

 
$
27,844

 


26

Comparison of Years Ended December 31, 2013 and 2012

Revenues. For the years ended December 31, 2013 and 2012, revenues were $2.188 billion and $1.920 billion, respectively. The $268.2 million increase from 2012 to 2013 was primarily due to the growth of our hydraulic fracturing business, which resulted in an increase in hydraulic fracturing revenues of approximately $482.6 million, partially offset by decreases in revenues of $174.4 million and $74.2 million for our drilling and oilfield rental segments, respectively. The growth in hydraulic fracturing revenues was due to an increase in the number of stages completed from 2,806 in 2012 to 7,124 in 2013. The decrease in revenues for our drilling and oilfield rental segments was due primarily to an overall reduction in drilling activity by Chesapeake and secondarily, a decrease in the size of our drilling rig fleet and market pricing pressure for our oilfield rentals segment, partially offset by an increase in revenues from third parties. The majority of our revenues are derived from Chesapeake and its working interest partners. Our revenues for the years ended December 31, 2013 and 2012 are detailed below:
 
Years Ended December 31,
 
2013
 
2012
 
(in thousands)
Drilling
$
740,812

 
$
915,208

Hydraulic fracturing
897,809

 
415,168

Oilfield rentals
160,241

 
234,456

Oilfield trucking
244,380

 
226,161

Other operations
144,963

 
129,029

Total
$
2,188,205

 
$
1,920,022


Operating Costs. As a percentage of revenues, operating costs were 78% and 72% for the years ended December 31, 2013 and 2012, respectively. The increase in operating costs as a percentage of revenues from 2012 to 2013 was primarily attributable to lower utilization rates and pricing pressure for certain segments, which compressed margins. Operating costs for the years ended December 31, 2013 and 2012 were $1.718 billion and $1.391 billion, respectively. The increase in operating costs from 2012 to 2013 was due primarily to the growth of our hydraulic fracturing business, which resulted in an increase in hydraulic fracturing operating costs of approximately $437.4 million, partially offset by decreases in operating costs of $124.9 million for our drilling segment. The decrease in operating costs for our drilling segment was due primarily to an overall reduction in drilling and completion activity by Chesapeake and a decrease in the size of our drilling rig fleet. Our operating costs for the years ended December 31, 2013 and 2012 are detailed below:

 
Years Ended December 31,
 
2013
 
2012
 
 
(in thousands)
Drilling
$
543,279

 
$
668,203

 
Hydraulic fracturing
740,439

 
303,079

 
Oilfield rentals
101,746

 
134,075

 
Oilfield trucking
207,692

 
173,327

 
Other operations
124,553

 
112,102

 
Total
$
1,717,709

 
$
1,390,786

 

Drilling

Drilling revenues for the year ended December 31, 2013 decreased $174.4 million, or 19%, from the year ended December 31, 2012 primarily due to an overall reduction in drilling activity by Chesapeake and a reduction in the size of our drilling rig fleet. Our average number of operating drilling rigs decreased from 98 in 2012 to 80 in 2013, largely due to Chesapeake's reduced drilling activity and the sale of 32 non-essential drilling rigs during 2012 and 2013 as part of our ongoing strategic positioning process. The 32% decrease in our revenues from Chesapeake was partially offset by an increase in revenues from third parties of $69.2 million from 2012 to 2013. Revenues from third parties increased to 20% of total segment revenues for 2013 compared to 9% for 2012.


27

Drilling operating costs for the year ended December 31, 2013 decreased $124.9 million, or 19%, from the year ended December 31, 2012. This decrease was primarily due to an overall reduction in drilling activity by Chesapeake and a decrease in the size of our drilling rig fleet. The decrease in our average number of operating rigs resulted in lower labor-related costs, repairs and maintenance and other operating costs. Our average employee headcount decreased 17% from 2012 to 2013. As a percentage of drilling revenues, drilling operating costs were 73% for both 2013 and 2012.

Hydraulic Fracturing

Hydraulic fracturing revenues for the year ended December 31, 2013 increased $482.6 million, or 116%, from the year ended December 31, 2012. This increase was due to an increase in our average number of operating fleets from five in 2012 to eight in 2013 resulting in a 154% increase in completed stages, partially offset by a 15% decrease in revenue per stage from 2012 to 2013. The decrease in revenue per stage was due primarily to pricing pressure.

Hydraulic fracturing operating costs for the year ended December 31, 2013 increased $437.4 million, or 144%, from the year ended December 31, 2012 primarily due to a 154% increase in the number of completed stages. As a percentage of hydraulic fracturing revenues, hydraulic fracturing operating costs increased from 73% in 2012 to 82% in 2013. This increase was primarily attributable to pricing pressure for our hydraulic fracturing services and an increase in product costs, which compressed margins. Revenue per stage decreased 15% from 2012 to 2013. As a percentage of hydraulic fracturing revenues, product costs were 50% in 2013 and 42% in 2012. These increases were partially offset by a reduction in labor-related costs, which as a percentage of hydraulic fracturing revenues, decreased from 11% in 2012 to 8% in 2013.

Oilfield Rentals

Oilfield rental revenues for the year ended December 31, 2013 decreased $74.2 million, or 32%, from the year ended December 31, 2012 primarily due to lower utilization as a result of Chesapeake’s reduction in drilling and completion activity and market pricing pressure for certain of our equipment. The utilization of our oilfield rental equipment has historically correlated with fluctuations in Chesapeake’s drilling and completion activity.

Oilfield rental operating costs for the year ended December 31, 2013 decreased $32.3 million, or 24%, from the year ended December 31, 2012. The decrease was primarily due to an overall reduction in drilling and completion activity by Chesapeake, which resulted in lower labor-related costs, supplies, repairs and maintenance, freight and third party expenses. Our average oilfield rental employee headcount decreased 14% from 2012 to 2013. As a percentage of oilfield rental revenues, oilfield rental operating costs were 63% and 57% for 2013 and 2012, respectively. The increase in oilfield rental operating costs as a percentage of oilfield rental revenues from 2012 to 2013 was primarily attributable to pricing pressure for certain services, which compressed margins, and spreading fixed costs over a smaller revenue base. As a percentage of oilfield rental revenues, labor-related costs were 29% and 24% in 2013 and 2012, respectively.

Oilfield Trucking

Oilfield trucking revenues for the year ended December 31, 2013 increased $18.2 million, or 8%, from the year ended December 31, 2012. These increases were primarily due to the expansion of our crude hauling fleet, partially offset by lower revenues from our rig relocation services. Our fluid handling services revenues increased approximately $45.5 million from 2012 to 2013 due primarily to Chesapeake increasing activity in liquids-rich plays. The decrease in revenues from our rig relocation services was primarily due to an overall reduction in drilling and completion activity by Chesapeake.

Oilfield trucking operating costs for the year ended December 31, 2013 increased $34.4 million, or 20%, from the year ended December 31, 2012 primarily due to the growth of our fluid handling services. Our fluid handling services operating costs increased approximately $42.1 million from 2012 to 2013. As a percentage of oilfield trucking revenue, oilfield trucking operating costs were 85% and 77% for 2013 and 2012, respectively. The increase in operating costs as a percentage of revenue was primarily attributable to an increase in labor-related costs due to the competitive market for trucking labor. As a percentage of oilfield trucking revenues, labor-related costs were 42% and 34% for 2013 and 2012, respectively.

Other Operations

Our other operations consist primarily of our natural gas compression unit and related oil and gas production equipment manufacturing business and corporate functions. For the year ended December 31, 2013, revenues from our other operations increased $15.9 million, or 12%, from the year ended December 31, 2012. The increase was primarily due to a change in product mix and higher revenue rates. We sold natural gas compressor packages with total horsepower of approximately 138,000 and 130,000 in 2013 and 2012, respectively.

28


For the year ended December 31, 2013, operating costs for our other operations increased $12.5 million, or 11%, from the year ended December 31, 2012. The increase was primarily due to an increase in demand for our small natural gas compressors, which resulted in higher costs of goods sold. We sold natural gas compressor packages with total horsepower of approximately 138,000 and 130,000 in 2013 and 2012, respectively. As a percentage of compression manufacturing revenues, compression manufacturing costs were 85% and 87% in 2013 and 2012, respectively. The decrease in costs as a percentage of revenues was due to higher production of small natural gas compressors, which have comparatively higher margins.

Depreciation and Amortization. Depreciation and amortization for the years ended December 31, 2013 and 2012 was $289.6 million and $231.3 million, respectively. The increase reflects the additional investments in our asset base as a result of capital expenditures, primarily for new hydraulic fracturing equipment and PeakeRigs™. As a percentage of revenues, depreciation and amortization expense was 13% and 12% for 2013 and 2012, respectively.

General and Administrative Expenses. General and administrative expenses for the years ended December 31, 2013 and 2012 were $80.4 million and $66.4 million, respectively. The increase is due to hiring certain members of our senior management team in 2012 and additional allocated 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, all related to an increase in our overall operating activity. Our administrative expense allocation is based on a percentage of revenues for us and determined by Chesapeake using the estimated costs incurred on our behalf. These charges from Chesapeake were $55.5 million and $49.4 million for 2013 and 2012, respectively. As a percentage of revenues, general and administrative expenses were 4% and 3% for 2013 and 2012, respectively.

(Gains) Losses on Sales of Property and Equipment. During the year ended December 31, 2013, we sold 14 drilling rigs and ancillary equipment that were not being utilized in our business for $50.6 million, net of selling expenses. During the year ended December 31, 2012, we sold 18 drilling rigs and ancillary equipment that were not being utilized in our business for $47.4 million, net of selling expenses. We recorded net (gains) losses on sales of property and equipment of approximately ($2.6) million and $2.0 million related to these asset sales during the years ended December 31, 2013 and 2012, respectively.

Impairments and Other. During the years ended December 31, 2013 and 2012, we recognized $23.6 million and $11.8 million, respectively, of impairment charges for certain drilling rigs and spare equipment that we identified for sale as part of our broader strategy to divest non-essential drilling rigs. We also identified certain drilling rigs during the years ended December 31, 2013 and 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 demand. We recorded impairment charges of $25.4 million and $14.9 million during the years ended December 31, 2013 and 2012, respectively, related to these drilling rigs.

During the year ended December 31, 2013, we purchased 23 leased drilling rigs for approximately $140.2 million and paid lease termination costs of approximately $22.4 million. During the year ended December 31, 2012, we purchased 25 leased drilling rigs for approximately $36.2 million and paid lease termination costs of approximately $24.9 million. The lease termination costs are included in impairments and other in the consolidated statements of operations.

During the year ended December 31, 2012, we also identified certain excess drill pipe that had become obsolete. The carrying value of such drill pipe was reduced to fair value, and we recorded impairment charges of $7.5 million to reduce the carrying amount of such drill pipe to their estimated fair value.

We identified certain other property and equipment during the years ended December 31, 2013 and 2012 that we deemed to be impaired based on our assessment of the fair value of such assets. We recorded impairment charges of $3.4 million and $1.7 million during the years ended December 31, 2013 and 2012, respectively, related to these assets.

Interest Expense. Interest expense for the years ended December 31, 2013 and 2012 was $56.8 million and $53.5 million, respectively.

Loss from Equity Investees. Loss from equity investees was $1.0 million and $0.4 million for the years ended December 31, 2013 and 2012, respectively, which was a result of our investments in Maalt and Big Star.

Other Income. Other income for the years ended December 31, 2013 and 2012 was $1.8 million and $1.5 million, respectively.

Income Tax (Benefit) Expense. We recorded income tax (benefit) expense of ($7.8) million and $46.9 million for the years ended December 31, 2013 and 2012, respectively. The $54.7 million increase in income tax benefit recorded for 2013 was

29

primarily the result of a decrease in pre-tax income from $116.5 million of pre-tax income in 2012 to a pre-tax loss of $27.6 million in 2013. Our effective income tax rate for 2013 and 2012 was 28% and 40%, respectively. The decrease in our effective tax rate from 2012 to 2013 was primarily the result of permanent differences, including meals and entertainment, stock based compensation and fines and penalties, having a greater impact on our effective income tax rate due to lower pre-tax income or loss in 2013 compared to 2012.

Comparison of Years Ended December 31, 2012 and 2011

Revenues. For the years ended December 31, 2012 and 2011, revenues were $1.920 billion and $1.303 billion, respectively. The increase in revenues from 2011 to 2012 was due to the start-up of our hydraulic fracturing business in 2011 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, respectively, from 2011 to 2012. The majority of our revenues were derived from Chesapeake and its working interest partners. Our revenues for the years ended December 31, 2012 and 2011 are detailed below:
 
Years Ended December 31,
 
 
2012
 
2011
 
 
(in thousands)
 
Drilling
$
915,208

 
$
855,023

 
Hydraulic fracturing
415,168

 
13,005

 
Oilfield rentals
234,456

 
245,666

 
Oilfield trucking
226,161

 
127,042

 
Other operations
129,029

 
62,760

 
Total
$
1,920,022

 
$
1,303,496

 

    
Operating Costs. As a percentage of revenues, operating costs were 72% and 76% for the years ended December 31, 2012 and 2011, respectively. The decrease in operating costs as a percentage of revenues from 2011 to 2012 was 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. Operating costs for the years ended December 31, 2012 and 2011 were $1.391 billion and $986.2 million, respectively. Our operating costs for the years ended December 31, 2012 and 2011 are detailed below:

 
Years Ended December 31,
 
 
2012
 
2011
 
 
(in thousands)
 
Drilling
$
668,203

 
$
685,077

 
Hydraulic fracturing
303,079

 
21,787

 
Oilfield rentals
134,075

 
115,286

 
Oilfield trucking
173,327

 
109,098

 
Other operations
112,102

 
54,991

 
Total
$
1,390,786

 
$
986,239

 

Drilling

Drilling revenues for the year ended December 31, 2012 increased $60.2 million, or 7%, from the year ended December 31, 2011 primarily due to a $45.3 million increase in revenues from drilling-related services, including directional drilling, geosteering and mudlogging, and secondarily an increase in average revenue per day. These increases were partially offset by a decrease in the average number of operating drilling rigs from 104 to 98 for the years ended December 31, 2011 and 2012, respectively, resulting from our sale of 18 non-essential drilling rigs during 2012 as part of our strategic positioning process. Our average revenue per day increased 13% from 2012 to 2013.

Drilling operating costs for the year ended December 31, 2012 decreased $16.9 million, or 2%, from the year ended December 31, 2011 primarily due to a decrease in our average number of operating rigs from 104 to 98 for the years ended

30

December 31, 2011 and 2012, respectively. The decrease in our average number of operating rigs was the result of the 18 drilling rigs we sold during 2012 and a decrease in utilization. The decrease in our average number of operating rigs resulted in lower labor-related costs, repairs and maintenance and other operating costs. We also experienced a decrease in our utilization rate from 98% to 92% for the years ended December 31, 2011 and 2012, respectively, as we experienced lower demand for our drilling services. As a percentage of drilling revenues, drilling operating costs decreased from 80% to 73% for the years ended December 31, 2011 and 2012, respectively. This decrease was primarily attributable to a decrease in labor-related costs as a percentage of revenues due to a reduction in and more efficient use of our labor force.

Hydraulic Fracturing

Hydraulic fracturing revenues for the year ended December 31, 2012 were $415.2 million compared to $13.0 million for 2011. We began providing hydraulic fracturing services in October 2011 with one fleet and ended 2012 with seven fleets and an aggregate of 270,000 horsepower.

Hydraulic fracturing operating costs for the years ended December 31, 2012 and 2011 were $303.1 million and $21.8 million, respectively. As a percentage of hydraulic fracturing revenue, operating costs were 73% for the year ended December 31, 2012. The principal expenses involved in conducting our hydraulic fracturing business are product costs and freight, labor expenses and the costs of maintaining and repairing our hydraulic fracturing units.

Oilfield Rentals

Oilfield rental revenues for the year ended December 31, 2012 decreased $11.2 million, or 5%, from the year ended December 31, 2011 primarily due to a decrease in utilization as we mobilized our rental tools in conjunction with Chesapeake’s transition from natural gas to liquids-rich plays.

Oilfield rental operating costs for the year ended December 31, 2012 increased $18.8 million, or 16%, from the year ended December 31, 2011. As a percentage of oilfield rental revenues, oilfield rental operating costs were 57% and 47% for the years ended December 31, 2012 and 2011, respectively. The increase in operating costs as a percentage of revenues from 2011 to 2012 was primarily attributable to costs to mobilize equipment to new unconventional liquids-rich plays which resulted in higher labor-related costs and lower utilization of our assets. As a percentage of oilfield rental revenues, labor-related costs were 24% and 17% for the years ended December 31, 2012 and 2011, respectively.

Oilfield Trucking

Oilfield trucking revenues for the year ended December 31, 2012 increased $99.2 million, or 78%, from the year ended December 31, 2011 primarily due to an increase in the size of our rig relocation trucking fleet and a broadening of services provided by our oilfield trucking segment to include fluid handling services. We experienced a 38% increase in the size of our rig relocation fleet from December 31, 2011 to December 31, 2012, and our fluid handling revenues increased by $49.0 million from 2011 to 2012.

Oilfield trucking operating costs for the year ended December 31, 2012 increased $64.2 million, or 59%, from the year ended December 31, 2011. As a percentage of oilfield trucking revenue, oilfield trucking operating costs were 77% and 86% for the years ended December 31, 2012 and 2011, respectively. The decrease in oilfield trucking operating costs as a percentage of oilfield trucking revenues from 2011 to 2012 was primarily attributable to increased utilization resulting in a spread of our fixed costs over a larger revenue base and a reduction in lower-margin third-party rig moves.

Other Operations

For the year ended December 31, 2012, revenues from our other operations increased $66.2 million, or 106%, from the year ended December 31, 2011 primarily due to higher compression unit manufacturing capacity and increased demand from our customers. We sold natural gas compressor packages with total horsepower of approximately 130,000 and 60,000 for the years ended December 31, 2012 and 2011, respectively.

For the year ended December 31, 2012, operating costs for our other operations increased $57.1 million, or 104%, from the year ended December 31, 2011 primarily due to an increase in our overall compression unit manufacturing capacity and increased demand from our customers, which resulted in higher costs of goods sold. We sold compressor packages with total horsepower of approximately 130,000 and 60,000 during the years ended December 31, 2012 and 2011, respectively.


31

Depreciation and Amortization. Depreciation and amortization for the years ended December 31, 2012 and 2011 was $231.3 million and $175.8 million, respectively. The increase reflects the additional investments in our asset base as a result of capital expenditures, primarily for new hydraulic fracturing equipment and PeakeRigs™. As a percentage of revenues, depreciation and amortization expense was 12% and 13% for 2012 and 2011, respectively.

General and Administrative Expenses. General and administrative expenses for the years ended December 31, 2012 and 2011 were $66.4 million and $37.1 million, respectively. The increase is due to our hiring the majority of our senior management team in the second half of 2011 and early in 2012, and additional allocated 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 an increase in our overall operating activity. The administrative expense allocation is determined based on a percentage of revenues for us and Chesapeake using the estimated costs incurred on our behalf. These charges from Chesapeake were $49.4 million and $33.7 million for 2012 and 2011, respectively. As a percentage of revenues, general and administrative expenses were 3% for both 2012 and 2011.

Losses (Gains) on Sales of Property and Equipment. During the year ended December 31, 2012, we sold 18 drilling rigs and ancillary equipment that were not being utilized in our business for $47.4 million, net of selling expenses. During 2011, we sold ancillary equipment for $110.9 million, net of selling expenses. We recorded net losses (gains) on sales of property and equipment of approximately $2.0 million and ($3.6) million related to these asset sales during the years ended December 31, 2012 and 2011, respectively.

Impairments and Other. During the year ended December 31, 2012, we recognized $11.8 million of impairment charges for certain drilling rigs and spare equipment that we identified for sale as part of our broader strategy to divest non-essential drilling rigs. We also identified certain drilling 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 demand. We recorded impairment charges of $14.9 million during the year ended December 31, 2012, respectively, related to these drilling rigs. During the year ended December 31, 2012, we purchased 25 leased drilling rigs for approximately $36.2 million and paid lease termination costs of approximately $24.9 million.

During the year ended December 31, 2012, we also identified certain excess drill pipe that had become obsolete. The carrying value of such drill pipe was reduced to fair value, and we recorded impairment charges of $7.5 million to reduce the carrying amount of such drill pipe to its estimated fair value.

We identified certain other property and equipment during the years ended December 31, 2012 and 2011 that we deemed to be impaired based on our assessment of the fair value of such assets. We recorded impairment charges of $1.7 million and $2.7 million during the years ended December 31, 2012 and 2011, respectively, related to these assets.

Interest Expense. Interest expense for the years ended December 31, 2012 and 2011 was $53.5 million and $48.8 million, respectively. The increase from 2011 to 2012 was 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.

Loss from Equity Investees. Loss from equity investees was $0.4 million for the year ended December 31, 2012, which was a result of our investments in Maalt and Big Star.

Other Income (Loss). Other income (loss) for the years ended December 31, 2012 and 2011 was $1.5 million and ($2.5) million, respectively.

Income Tax Expense. We recorded income tax expense of $46.9 million and $26.3 million for the years ended December 31, 2012 and 2011, respectively. The $20.6 million increase in income tax expense recorded for 2012 was primarily the result of an increase in pre-tax income of $62.5 million from 2011 to 2012. Our effective income tax rate for 2012 and 2011 was 40% and 49%, respectively. The decrease in our effective tax rate from 2011 to 2012 was primarily the result of permanent differences, including meals and entertainment, stock based compensation and fines and penalties, having a smaller impact on our effective income tax rate due to lower pre-tax income or loss in 2011 compared to 2012.

Contractual Commitments and Obligations

In the normal course of business, we enter into various contractual obligations that impact, or could impact, our liquidity. The following table summarizes our material obligations as of December 31, 2013:


32

 
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
405,000

 
—

 
405,000

 
—

 
—

Interest(a)
258,376

 
43,063

 
86,125

 
86,125

 
43,063

Purchase obligations(b)
29,700

 
29,700

 
—

 
—

 
—

Operating leases(c)
115,345

 
74,511

 
28,712

 
11,400

 
722

Total
$
1,458,421

 
$
147,274

 
$
519,837

 
$
97,525

 
$
693,785

(a)    Amount includes contractual interest payments on the 2019 Senior Notes.
(b)    Consists of unconditional obligations to purchase equipment. See Note 6 to our consolidated financial statements included in Item 8 of this report.
(c)    Consists of drilling rig, real property and rail car leases. Amounts disclosed assume no exercise of options to renew or extend the leases. See "—Off-Balance Sheet Arrangements."

Off-Balance Sheet Arrangements

As of December 31, 2013, we leased 45 rigs under master lease agreements with an aggregate undiscounted future lease commitment of $76.2 million. For more information regarding the terms of the rig lease transactions, please see Note 6 “Commitments and Contingencies” to our consolidated financial statements included in Item 8 of this report.

In October 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 from 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 will increase by 2.5% each year. We make monthly payments to Chesapeake under the facilities 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 December 31, 2013, we were party to six lease agreements with various third parties to lease rail cars for initial terms of three to seven years. Additional rental payments are required for the use of rail cars in excess of the allowable mileage stated in the respective agreement. We account for these leases as operating leases.

Aggregate undiscounted minimum future lease payments as of December 31, 2013 under our operating leases are presented below:
 
 
December 31, 2013
 
Rigs
 
Real Property
 
Rail Cars
 
Total
 
(in thousands)
2014
$
51,395

 
$
16,898

 
$
6,218

 
$
74,511

2015
11,450

 
—

 
5,823

 
17,273

2016
5,616

 
—

 
5,823

 
11,439

2017
7,164

 
—

 
2,168

 
9,332

2018
623

 
—

 
1,445

 
2,068

After 2018
—

 
—

 
722

 
722

Total
$
76,248

 
$
16,898

 
$
22,199

 
$
115,345



33

Other Commitments

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, 2013, we had $29.7 million of purchase commitments related to future inventory and capital expenditures that we expect to incur in 2014.

In October 2011, we entered into an agreement to acquire 49% of the membership interest in Maalt. Under the agreement, we could be required to make future additional payments not to exceed $3.0 million which are contingent upon Maalt meeting certain financial and operational performance targets. For each year in the three-year period that began December 6, 2011, we will determine whether Maalt has met the specified performance targets for the preceding year. If 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 December 31, 2013, we had accrued $0.4 million 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 is re-determined on a monthly basis. We have guaranteed to Maalt that through December 31, 2014, 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. No payments for non utilization were required for the years ended December 31, 2013 or 2012.

Critical Accounting Policies

Our consolidated financial statements are prepared in accordance with generally accepted accounting principles, which require us to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the dates of the financial statements and the reported amounts of revenues and expenses during the reported periods.

Property and Equipment

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

Impairment of Long-Lived Assets
    
We review our long-lived assets, such as property and equipment, whenever, in management’s judgment, events or changes in circumstances indicate the carrying amount of the assets may not be fully 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, Intangible Assets and Amortization
    
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.

34

    
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.

Revenue Recognition

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 volume and recognize revenue as services are performed.
 

Other Operations. We design, engineer and fabricate natural gas compression 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.

35


Income Taxes
    
Chesapeake and its subsidiaries historically have filed a consolidated federal income tax return and other state returns as required. COO and its subsidiaries (other than Chesapeake Oilfield Finance, Inc., or COF) 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 for 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 or revolving bank credit facility, in which case such amounts will be treated as a 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 income tax valuation allowance as of December 31, 2013 and 2012.

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 as of December 31, 2013 and 2012.

New Accounting Pronouncements

To reduce diversity in practice related to the presentation of unrecognized tax benefits, in July 2013 the Financial Accounting Standards Board ("FASB") issued guidance requiring the presentation of an unrecognized tax benefit in the financial statements as a reduction to a deferred tax asset for a net operating loss carryforward, a similar tax loss or a tax credit carryforward. This net presentation is required unless a net operating loss carryforward, a similar tax loss or a tax credit carryforward is not available at the reporting date or the tax law of the jurisdiction does not require, and the entity does not intend to use, the deferred tax asset to settle any additional income tax that would result from the disallowance of the unrecognized tax benefit. The guidance was effective on January 1, 2014. The adoption of this standard did not have a material impact on our consolidated financial statements.

Inflation

Inflation in the U.S. has been relatively low in recent years and did not have a material impact on our results of operations for the years ended December 31, 2013, 2012 and 2011. 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.

Item 7A.
Quantitative and Qualitative Disclosures About Market Risk
 
 
 

Historically, we have provided substantially all of our oilfield services to Chesapeake and its working interest partners. For the years ended December 31, 2013, 2012 and 2011, Chesapeake and its working interest partners accounted for approximately 90%, 94% and 94% of our revenues, respectively. 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 Credit Facility and further limit our ability to fund our planned capital expenditures.

Changes in interest rates affect the amount of interest we earn on our cash, cash equivalents and short-term investments and the interest rate we pay on borrowings under our 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

36

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 primary exposure to interest rate risk results from outstanding borrowings under our Credit Facility. Outstanding borrowings under our 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 Credit Facility would have resulted in a $2.5 million increase or decrease in net income for the year ended December 31, 2013.

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.



37

Item 8.
Financial Statements and Supplementary Data
 
 
 

INDEX TO FINANCIAL STATEMENTS
CHESAPEAKE OILFIELD OPERATING, L.L.C.
 
Page
Consolidated Financial Statements:
 
Report of Independent Registered Public Accounting Firm
Consolidated Balance Sheets at December 31, 2013 and 2012
Consolidated Statements of Operations for the Years Ended December 31, 2013, 2012 and 2011
Consolidated Statements of Changes in Equity for the Years Ended December 31, 2013, 2012 and 2011
Consolidated Statements of Cash Flows for the Years Ended December 31, 2013, 2012 and 2011
Notes to Consolidated Financial Statements


38

Report of Independent Registered Public Accounting Firm
To the Member of Chesapeake Oilfield Operating, L.L.C.:
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, 2013 and 2012, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2013 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 11 and 12 to the accompanying consolidated financial statements, the Company earned the majority of its revenues and has other significant transactions with affiliated entities.
/s/ PricewaterhouseCoopers LLP
Tulsa, Oklahoma
March 14, 2014


39

CHESAPEAKE OILFIELD OPERATING, L.L.C.
Consolidated Balance Sheets
 
December 31,
 
2013
 
2012
 
(in thousands)
Assets:
 
 
 
Current Assets:
 
 
 
Cash
$
1,678

 
$
1,227

Accounts receivable, net of allowance of $524 and $496 at December 31, 2013 and December 31, 2012, respectively
62,959

 
25,910

Affiliate accounts receivable
312,480

 
337,705

Inventory
45,035

 
52,228

Deferred income tax asset
5,318

 
3,305

Prepaid expenses and other
20,301

 
24,484

Total Current Assets
447,771

 
444,859

Property and Equipment:
 
 
 
Property and equipment, at cost
2,241,350

 
2,096,150

Less: accumulated depreciation
(773,282
)
 
(541,117
)
Property and equipment held for sale, net
29,408

 
26,486

Total Property and Equipment, Net
1,497,476

 
1,581,519

Other Assets:
 
 
 
Investments
13,236

 
18,216

Goodwill
42,447

 
42,447

Intangible assets, net
7,429

 
11,382

Deferred financing costs
14,080

 
16,741

Other long-term assets
4,454

 
4,347

Total Other Assets
81,646

 
93,133

Total Assets
$
2,026,893

 
$
2,119,511

Liabilities and Equity:
 
 
 
Current Liabilities:
 
 
 
Accounts payable
$
30,666

 
$
28,810

Affiliate accounts payable
34,200

 
31,592

Other current liabilities
210,123

 
228,342

Total Current Liabilities
274,989

 
288,744

Long-Term Liabilities:
 
 
 
Deferred income tax liabilities
145,747

 
149,932

Senior notes
650,000

 
650,000

Revolving credit facility
405,000

 
418,200

Other long-term liabilities
3,965

 
15,818

Total Long-Term Liabilities
1,204,712

 
1,233,950

Commitments and Contingencies (Note 6)

 

Owner’s Equity
547,192

 
596,817

Total Liabilities and Equity
$
2,026,893

 
$
2,119,511


The accompanying notes are an integral part of these consolidated financial statements.

40

CHESAPEAKE OILFIELD OPERATING, L.L.C.
Consolidated Statements of Operations
 
Years Ended December 31,
 
2013
 
2012
 
2011
 
 
(in thousands)
Revenues:
 
 
 
 
 
 
Revenues from Chesapeake
$
1,960,256

 
$
1,811,253

 
$
1,226,420

 
Revenues from third parties
227,949

 
108,769

 
77,076

 
Total Revenues
2,188,205

 
1,920,022

 
1,303,496

 
Operating Expenses:
 
 
 
 
 
 
Operating costs
1,717,709

 
1,390,786

 
986,239

 
Depreciation and amortization
289,591

 
231,322

 
175,790

 
General and administrative, including expenses from affiliates (Notes 1 and 12)
80,354

 
66,360

 
37,074

 
(Gains) losses on sales of property and equipment
(2,629
)
 
2,025

 
(3,571
)
 
Impairments and other
74,762

 
60,710

 
2,729

 
Total Operating Expenses
2,159,787

 
1,751,203

 
1,198,261

 
Operating Income
28,418

 
168,819

 
105,235

 
Other Income (Expense):
 
 
 
 
 
 
Interest expense
(56,786
)
 
(53,548
)
 
(48,802
)
 
Loss from equity investees
(958
)
 
(361
)
 
—

 
Other income (loss)
1,758

 
1,543

 
(2,464
)
 
Total Other Expense
(55,986
)
 
(52,366
)
 
(51,266
)
 
(Loss) Income Before Income Taxes
(27,568
)
 
116,453

 
53,969

 
Income Tax (Benefit) Expense
(7,833
)
 
46,877

 
26,279

 
Net (Loss) Income
(19,735
)
 
69,576

 
27,690

 
Less: Net Loss Attributable to Noncontrolling Interest
—

 
—

 
(154
)
 
Net (Loss) Income Attributable to Chesapeake Oilfield Operating
$
(19,735
)
 
$
69,576

 
$
27,844

 

The accompanying notes are an integral part of these consolidated financial statements.

41

CHESAPEAKE OILFIELD OPERATING, L.L.C.
Consolidated Statements of Changes in Equity
 
 
Owner's
 
Noncontrolling
 
Total
 
Equity
 
Interest
 
Equity
 
(in thousands)
Balance at January 1, 2011
$
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

Net loss
(19,735
)
 
—

 
(19,735
)
Distributions to owner, net
(29,890
)
 
—

 
(29,890
)
Balance at December 31, 2013
$
547,192

 
$
—

 
$
547,192


The accompanying notes are an integral part of these consolidated financial statements.

42

CHESAPEAKE OILFIELD OPERATING, L.L.C.
Consolidated Statements of Cash Flows
 
 
Years Ended December 31,
 
2013
 
2012
 
2011
 
(in thousands)
CASH FLOWS FROM OPERATING ACTIVITIES:
 
 
 
 
 
NET (LOSS) INCOME
$
(19,735
)
 
$
69,576

 
$
27,690

ADJUSTMENTS TO RECONCILE NET INCOME TO CASH PROVIDED BY OPERATING ACTIVITIES:
 
 
 
 
 
Depreciation and amortization
289,591

 
231,322

 
175,790

Amortization of sale/leaseback gains
(15,995
)
 
(8,821
)
 
(6,282
)
Amortization of deferred financing costs
2,928

 
2,906

 
523

(Gains) losses on sales of property and equipment
(2,629
)
 
2,025

 
(3,571
)
Impairments
52,400

 
35,855

 
2,729

Loss from equity investees
958

 
361

 
—

Provision for doubtful accounts
436

 
310

 
—

Stock-based compensation
—

 
—

 
10,906

Deferred income tax (benefit) expense
(9,255
)
 
46,128

 
26,149

Other
1,641

 
264

 
(22
)
Changes in operating assets and liabilities, net of effects from acquisitions
 
 
 
 
 
Accounts receivable
(37,485
)
 
5,592

 
15,987

Affiliate accounts receivable
25,100

 
(165,249
)
 
(84,900
)
Inventory
7,193

 
(23,782
)
 
(12,981
)
Accounts payable
1,856

 
(9,562
)
 
11,338

Affiliate accounts payable
2,608

 
(6,126
)
 
36,395

Other current liabilities
38,324

 
33,957

 
58,615

Other
(865
)
 
(3,605
)
 
(18,320
)
Net cash provided by operating activities
337,071

 
211,151

 
240,046

CASH FLOWS FROM INVESTING ACTIVITIES:
 
 
 
 
 
Additions to property and equipment
(349,806
)
 
(622,825
)
 
(412,753
)
Acquisition of businesses, net of cash acquired
—

 
—

 
(339,962
)
Proceeds from sales of assets
50,602

 
47,421

 
110,902

Proceeds from sale of investment
2,790

 
—

 
—

Additions to investments
(431
)
 
(1,920
)
 
(16,657
)
Other
28

 
—

 
—

Net cash used in investing activities
(296,817
)
 
(577,324
)
 
(658,470
)
CASH FLOWS FROM FINANCING ACTIVITIES:
 
 
 
 
 
(Distributions to) contributions from owner
(29,890
)
 
(22,330
)
 
453,166

Decrease in affiliate debt
—

 
—

 
(635,070
)
Borrowings from revolving credit facility
1,216,900

 
1,389,100

 
168,000

Payments on revolving credit facility
(1,230,100
)
 
(999,900
)
 
(139,000
)
Proceeds from issuance of senior notes, net of offering costs
—

 
—

 
637,000

Deferred financing costs
—

 
—

 
(7,168
)
Payments on third party notes
—

 
—

 
(55,213
)
Acquisition of noncontrolling interest
—

 
—

 
(3,131
)
Other
3,287

 
—

 
—

Net cash (used in) provided by financing activities
(39,803
)
 
366,870

 
418,584

Net increase in cash
451

 
697

 
160

Cash, beginning of period
1,227

 
530

 
370

Cash, end of period
$
1,678

 
$
1,227

 
$
530

 
 
 
 
 
 
SUPPLEMENTAL DISCLOSURE OF SIGNIFICANT NON-CASH INVESTING AND FINANCING ACTIVITIES:
 
 
 
 
 
(Decrease) increase in other current liabilities related to purchases of property and equipment
$
(54,457
)
 
$
30,466

 
$
(31,146
)
Decrease in contributions from owner due to transfer of land and buildings
$
—

 
$
—

 
$
85,868

Decrease (increase) in contributions from (distributions to) owner due to transfer of tax attributes
$
—

 
$
(675
)
 
$
16,471

SUPPLEMENTAL DISCLOSURE OF CASH PAYMENTS:
 
 
 
 
 
Interest, net of amount capitalized
$
55,250

 
$
51,579

 
$
1,493


The accompanying notes are an integral part of these consolidated financial statements.

43
CHESAPEAKE OILFIELD OPERATING, L.L.C.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS



1. Organization, Basis of Presentation and Nature of Business

Organization

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 Services, L.L.C., Performance Technologies, L.L.C., PTL Prop Solutions, L.L.C., Western Wisconsin Sand Company, LLC (“WWS”), Thunder Oilfield Services, L.L.C., Hodges Trucking Company, L.L.C., Oilfield Trucking Solutions, L.L.C., Great Plains Oilfield Rental, L.L.C., Keystone Rock & Excavation, L.L.C., Compass Manufacturing, L.L.C. and Mid-States Oilfield Supply LLC.

Basis of Presentation

The accompanying consolidated financial statements and related notes include the accounts of COO and its subsidiaries, all of which are 100% owned. 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.

Chesapeake Oilfield Finance, Inc. (“COF”) is a 100% owned finance subsidiary of COO that was incorporated for the purpose of facilitating the offering of COO’s 6.625% Senior Notes due 2019 (see Note 4). COF does not have any operations or revenues.

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 with affiliates (see Note 12).

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 $55.5 million, $49.4 million and $33.7 million for the years ended December 31, 2013, 2012 and 2011, respectively. Management believes that the allocated charges are representative of the costs and expenses incurred by Chesapeake on behalf of COO. See Note 12 for a discussion of the methods of allocation.

Nature of Business

We provide a wide range of wellsite services and equipment, including drilling, hydraulic fracturing, oilfield rentals, rig relocation, fluid handling and disposal and manufacturing of natural gas compressor packages. We conduct our operations in Colorado, Kansas, Louisiana, Montana, New Mexico, Ohio, Oklahoma, Pennsylvania, Texas, West Virginia, Wisconsin and Wyoming. As of December 31, 2013, our primary owned assets consisted of 70 drilling rigs, nine hydraulic fracturing fleets, 260 rig relocation trucks, 67 cranes and forklifts and 246 fluid hauling trucks. Additionally, we had 45 rigs leased under contracts at December 31, 2013 (see Note 6). Our reportable business segments are drilling, hydraulic fracturing, oilfield rentals, oilfield trucking and other operations (see Note 13).


44
CHESAPEAKE OILFIELD OPERATING, L.L.C.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

2. Significant Accounting Policies

Accounting Estimates

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:
•
estimated useful lives of assets, which impacts depreciation and amortization of property and equipment;
•
impairment of long-lived assets, goodwill and intangibles;
•
income taxes;
•
accruals related to revenue, expenses, capital costs and contingencies; and
•
cost allocations as described in Note 12.

Risks and Uncertainties

Historically, we have provided substantially all of our oilfield services to Chesapeake. For the years ended December 31, 2013, 2012 and 2011, Chesapeake accounted for approximately 90%, 94% and 94%, respectively, of our revenues. Approximately 73% of Chesapeake’s estimated proved reserves volumes as of December 31, 2013 were natural gas and 75% of Chesapeake’s 2013 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.

Chesapeake’s current business strategy includes a decrease in its capital expenditure budget for 2014 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 and equipment. Any further reductions could have a material adverse effect on our business, financial condition and results of operations. As we apply available cash from future asset sales and operations towards reducing our financial leverage, we may incur various cash and noncash charges, including but not limited to, impairments of fixed assets or lease termination costs.

Accounts Receivable

Trade accounts receivable are recorded at the invoice amount and do not bear interest. The majority of our receivables, 83% and 93% at December 31, 2013 and 2012, respectively, are with Chesapeake and its subsidiaries. The allowance for doubtful accounts represents 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 the years ended December 31, 2013, 2012 and 2011, we recognized $0.4 million, $0.3 million and $0, respectively, of bad debt expense related to potentially uncollectible receivables. We also recognized reductions to our allowance of $0.4 million, a nominal amount and $0.2 million as we wrote off specific receivables against our allowance for the years ended December 31, 2013, 2012 and 2011, respectively.


45
CHESAPEAKE OILFIELD OPERATING, L.L.C.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

Inventory
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:

 
 
December 31,
 
 
2013
 
2012
 
 
(in thousands)
Raw materials, components and supplies
 
$
40,725

 
$
48,223

Work in process
 
4,310

 
4,005

Total inventory
 
$
45,035

 
$
52,228


Property and Equipment

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. Expenditures for maintenance and repairs that do not add capacity or extend the useful life of an asset are expensed as incurred.

A summary of our property and equipment amounts and useful lives is as follows:
 
 
 
 
 
 
Estimated
 
 
December 31,
 
Useful
 
 
2013
 
2012
 
Life
 
 
(in thousands)
 
(in years)
Drilling rigs and related equipment
 
$
1,146,747

 
$
988,968

 
3-15
Hydraulic fracturing equipment
 
332,051

 
306,873

 
2-7
Oilfield rental equipment
 
327,430

 
332,066

 
2-10
Trucking and fluid disposal equipment
 
209,255

 
210,472

 
5-8
Leasehold improvements
 
110,660

 
140,111

 
3-5
Vehicles
 
56,022

 
61,814

 
3
Buildings and improvements
 
5,731

 
6,018

 
3-39
Land
 
2,290

 
440

 
—
Other
 
51,164

 
49,388

 
3-10
Total property and equipment, at cost
 
2,241,350

 
2,096,150

 
 
Less: accumulated depreciation and amortization
 
(773,282
)
 
(541,117
)
 
 
Property and equipment held for sale, net
 
29,408

 
26,486

 
 
Total property and equipment, net
 
$
1,497,476

 
$
1,581,519

 
 
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, 2013, 2012 and 2011 was $285.6 million, $227.2 million and $173.2 million, respectively. Included in property and equipment are $106.1 million and $178.7 million at December 31, 2013 and 2012, respectively, of assets that are being constructed or have not been placed into service, and therefore are not subject to depreciation.

46
CHESAPEAKE OILFIELD OPERATING, L.L.C.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

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. Capitalized interest is added to the cost of the assets and amortized to depreciation expense over the useful life of the assets. During the years ended December 31, 2013, 2012 and 2011, we capitalized interest of approximately $1.1 million, $2.2 million and $0.9 million, respectively.
Impairment of Long-Lived Assets
We review our long-lived assets, such as property and equipment, whenever, in management’s judgment, events or changes in circumstances indicate the carrying amount of the assets may not be 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
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 9 for further discussion of investments.
Goodwill, Intangible Assets and Amortization
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. The goodwill is assigned to our drilling segment. 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.
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. For purposes of performing the impairment tests for goodwill, all of our goodwill relates to our drilling and drilling-related services reporting units.

47
CHESAPEAKE OILFIELD OPERATING, L.L.C.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

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:

 
 
 
 
 
 
Estimated
 
 
December 31,
 
Useful
 
 
2013
 
2012
 
Life
 
 
(in thousands)
 
(in years)
Customer relationships
 
$
19,600

 
$
19,600

 
3-20
Trade name
 
1,400

 
1,400

 
10
Total intangible assets, at cost
 
21,000

 
21,000

 
 
Less: accumulated amortization
 
(13,571
)
 
(9,618
)
 
 
Total intangible assets, net
 
$
7,429

 
$
11,382

 
 

Amortization expense was $3.9 million, $3.9 million and $2.6 million for the years ended December 31, 2013, 2012 and 2011, respectively. Future estimated amortization expense is presented below.

 
 
December 31,
 
 
2013
 
 
(in thousands)
2014
 
$
2,009

2015
 
620

2016
 
480

2017
 
480

2018
 
480

After 2018
 
3,360

Total
 
$
7,429

Deferred Financing Costs
Legal fees and other costs incurred in obtaining financing are amortized over the term of the related debt using a method that approximates the effective interest method. Gross deferred financing costs were $20.4 million at December 31, 2013 related to our Credit Facility and 6.625% Senior Notes due 2019. Prior to 2011, we had no deferred financing costs. Amortization expense related to deferred financing costs was $2.9 million, $2.9 million and $0.5 million for the years ended December 31, 2013, 2012 and 2011, respectively, and is included in interest expense in the consolidated statements of operations.
Accounts Payable
Included in accounts payable at December 31, 2013 and 2012 are liabilities of $7.7 million and $15.0 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.
Revenue Recognition
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.

48
CHESAPEAKE OILFIELD OPERATING, L.L.C.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

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 volume and recognize revenue as services are performed.
Other Operations. We design, engineer and fabricate natural gas compression 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.
Litigation Accruals
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.
Environmental Costs
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, 2013 and 2012. We record liabilities on an undiscounted basis when remediation efforts are probable and the costs to conduct such remediation efforts can be reasonably estimated.
Leases
We lease drilling rigs, real property and rail cars through various leasing arrangements (see Note 6). When we enter into a leasing arrangement, we analyze the terms of the arrangement to determine its accounting treatment. As of December 31, 2013, 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.
Income Taxes
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

49
CHESAPEAKE OILFIELD OPERATING, L.L.C.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

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.
A valuation allowance for deferred tax assets is recognized when it is more likely than not that some or all of the benefit from the deferred tax asset will not be realized. To assess that likelihood, we use estimates and judgment regarding our future taxable income, as well as the jurisdiction in which such taxable income is generated, to determine whether a valuation allowance is required. Such evidence can include our current financial position, our results of operations, both actual and forecasted, the reversal of deferred tax liabilities, and tax planning strategies as well as the current and forecasted business economics of our industry. We had no valuation allowance at December 31, 2013 and 2012.
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, 2013 and 2012.
3. Asset Sales, Assets Held for Sale and Impairments and Other

Asset Sales

During 2013, we sold 14 drilling rigs and ancillary equipment that were not being utilized in our business for $50.6 million, net of selling expenses. During 2012, we sold 18 drilling rigs and ancillary equipment that were not being utilized in our business for $47.4 million, net of selling expenses. During 2011, we sold ancillary equipment for $110.9 million, net of selling expenses. We recorded net (gains) losses on sales of property and equipment of approximately ($2.6) million, $2.0 million and ($3.6) million during the years ended December 31, 2013, 2012 and 2011, respectively.

Assets Held for Sale and Impairments and Other

A summary of our impairments and other is as follows:
 
 
Years Ended December 31,
 
 
2013
 
2012
 
2011
 
 
(in thousands)
Drilling rigs held for sale
 
$
23,574

 
$
11,750

 
$
—

Drilling rigs held for use
 
25,417

 
14,871

 
—

Lease termination costs
 
22,362

 
24,855

 
—

Drill pipe
 
—

 
7,486

 
—

Other
 
3,409

 
1,748

 
2,729

Total impairments and other
 
$
74,762

 
$
60,710

 
$
2,729


During the years ended December 31, 2013 and 2012, we recognized $23.6 million and $11.8 million, respectively, of impairment charges for certain drilling rigs and spare equipment we had identified to sell as part of our broader strategy to divest of 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. Estimated fair value was based on the expected sales price, less costs to sell. Included in property and equipment held for sale on our consolidated balance sheet was $29.4 million and $26.5 million as of December 31, 2013 and 2012, respectively. These assets are included in our drilling segment. The assets classified as held for sale as of December 31, 2012 were sold during 2013.

We also identified certain drilling rigs during the years ended December 31, 2013 and 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 demand. We recorded impairment charges of $25.4 million and $14.9 million during the years ended December 31, 2013 and 2012, respectively, related to these drilling rigs. Estimated fair value for these drilling rigs was determined using significant unobservable inputs (Level 3) based on a market approach.

During the year ended December 31, 2013, we purchased 23 leased drilling rigs for approximately $140.2 million and paid lease termination costs of approximately $22.4 million. During the year ended December 31, 2012, we purchased 25 leased drilling rigs for approximately $36.2 million and paid lease termination costs of approximately $24.9 million.

50
CHESAPEAKE OILFIELD OPERATING, L.L.C.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)


During the year ended December 31, 2012, we also identified certain excess drill pipe that had become obsolete. The carrying value of such drill pipe was reduced to fair value, and we recorded impairment charges of $7.5 million based on the difference between carrying amount and fair value of such drill pipe.

We identified certain other property and equipment during the years ended December 31, 2013, 2012 and 2011 that we deemed to be impaired based on our assessment of the market value and expected future cash flows of the long-lived asset. We recorded impairment charges of $3.4 million, $1.7 million and $2.7 million during the years ended December 31, 2013, 2012 and 2011, respectively, related to these assets. Estimated fair value for this property and equipment was determined using significant unobservable inputs (Level 3) based on an income approach.
 
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. A prolonged period of lower oil and natural gas prices or additional reduction in capital expenditures by Chesapeake or our third-party customers, 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. As we apply available cash from future asset sales and operations towards reducing our financial leverage, we may incur various cash and noncash charges, including but not limited to, impairments of fixed assets or lease termination costs.

4. Debt

2019 Senior Notes

In October 2011, we issued $650.0 million in aggregate principal amount of 6.625% Senior Notes due 2019 (the “2019 Senior Notes”). We incurred $14.8 million in financing costs related to the 2019 Senior 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 in arrears on May 15 and November 15 of each year. The 2019 Senior Notes are guaranteed by all of our existing subsidiaries other than certain immaterial subsidiaries and COF, which is a co-issuer 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 (the “Indenture”), 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:
 
Year
Redemption
Price
2015
103.313
%
2016
101.656
%
2017 and thereafter
100.000
%

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. 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 from either Moody’s Investors Service, Inc. (“Moody’s”) or Standard &

51
CHESAPEAKE OILFIELD OPERATING, L.L.C.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

Poor’s Rating Services (“S&P”), our obligation to comply with certain of these covenants will be suspended, and if the 2019 Senior Notes achieve an investment grade rating from both 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 2019 Senior Notes offering enabling holders of the 2019 Senior Notes to exchange the privately placed 2019 Senior Notes for publicly registered exchange notes with substantially identical terms. We also agreed to make additional interest payments, up to a maximum of 1.0% per annum, to holders of the 2019 Senior Notes if we did not comply with such obligation under the registration rights agreement. We incurred approximately $0.9 million of additional interest expense related to our delay in filing such registration statement, which was paid on May 15, 2013. We completed the exchange offer on July 19, 2013.

Revolving Credit Facility

In November 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 December 31, 2013, the Credit Facility was not subject to any such limitations and had borrowing availability of approximately $95.0 million. We use the Credit Facility 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 $0.7 million, $1.4 million and $0.4 million for the years ended December 31, 2013, 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 restricted subsidiaries’ ability to enter into asset sales, incur additional indebtedness, make investments or loans and create liens. The Credit Facility requires maintenance of a leverage ratio based on the ratio of lease-adjusted indebtedness to earnings before interest, taxes, depreciation, amortization and rental expense (EBITDAR), a senior secured leverage ratio based on the ratio of secured indebtedness to EBITDA and a fixed charge coverage ratio based on the ratio of EBITDAR to lease-adjusted interest expense, in each case as defined in the Credit Facility agreement. We were in compliance with these covenants under the agreement as of December 31, 2013. If we or our restricted subsidiaries should fail to perform our obligations under the agreement, 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 the Indenture, which could in turn result in the acceleration of our 2019 Senior Notes. The Credit Facility also contains cross-default provisions that apply to other indebtedness, including our 2019 Senior Notes, that we and our restricted 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.
Affiliate Debt

In October, 2011, we issued our 2019 Senior Notes 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 for the year ended December 31, 2011 was based on Chesapeake’s average borrowing rate. The average outstanding affiliate debt was $317.5 million for the year ended December 31, 2011.

52
CHESAPEAKE OILFIELD OPERATING, L.L.C.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

5. Other Current and Long-Term Liabilities

Other current and long-term liabilities as of December 31, 2013 and 2012 are detailed below:
 
 
December 31,
 
2013
 
2012
 
(in thousands)
Other Current Liabilities:
 
 
 
Operating expenditures
$
101,007

 
$
85,231

Payroll related
47,796

 
37,828

Self-insurance reserves
27,245

 
25,907

Property, sales, use and other taxes
17,904

 
4,503

Property and equipment
7,010

 
61,467

Interest
5,862

 
7,266

Deferred gain on sale/leasebacks
3,299

 
6,140

Total Other Current Liabilities
$
210,123

 
$
228,342

Other Long-Term Liabilities:
 
 
 
Deferred gain on sale/leasebacks
$
2,115

 
$
15,270

Payroll related
1,231

 
—

Other
619

 
548

Total Other Long-Term Liabilities
$
3,965

 
$
15,818


6. Commitments and Contingencies

Rent expense for rigs, real property, rail cars and other property and equipment for the years ended December 31, 2013, 2012 and 2011 was $103.9 million, $121.4 million and $108.5 million, respectively, and was included in operating costs in our consolidated statements of operations.

Rig Leases

As of December 31, 2013, we leased 45 rigs under master lease agreements with an aggregate undiscounted future lease commitment of $76.2 million. The lease commitments are guaranteed by Chesapeake and certain of its subsidiaries. Under the leases, we can exercise an early purchase option or we can purchase the rigs at expiration of the lease for the fair market value at the time. In addition, in most cases, we have the option to renew a lease for negotiated new terms at the expiration of the lease. Subsequent to December 31, 2013, we purchased 14 leased drilling rigs and terminated the applicable lease arrangements for approximately $62.3 million, lowering our minimum aggregate undiscounted future rig lease payments by approximately $29.0 million. See Note 17 for further discussion of the purchases.

Real Property Leases

In October 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 will increase by 2.5% each year. We make monthly payments to Chesapeake under the facilities 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.

Rail Car Leases

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

53
CHESAPEAKE OILFIELD OPERATING, L.L.C.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

Aggregate undiscounted minimum future lease payments under our operating leases are presented below:
 
 
December 31, 2013
 
Rigs
 
Real Property
 
Rail Cars
 
Total
 
(in thousands)
2014
$
51,395

 
$
16,898

 
$
6,218

 
$
74,511

2015
11,450

 
—

 
5,823

 
17,273

2016
5,616

 
—

 
5,823

 
11,439

2017
7,164

 
—

 
2,168

 
9,332

2018
623

 
—

 
1,445

 
2,068

After 2018
—

 
—

 
722

 
722

Total
$
76,248

 
$
16,898

 
$
22,199

 
$
115,345


Other Commitments

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, 2013, we had $29.7 million of purchase commitments related to future inventory and capital expenditures that we expect to incur in 2014.

In October 2011, we entered into an agreement to acquire 49% of the membership interest in Maalt Specialized Bulk, L.L.C. (“Maalt”) (see Note 9). Maalt provides bulk transportation, transloading and sand hauling services, and its assets consist primarily of trucks and trailers.  Under the agreement, we could be required to make future additional payments not to exceed $3.0 million which are contingent upon Maalt meeting certain financial and operational performance targets. For each year in the three-year period that began December 6, 2011, we will determine whether Maalt has met the specified performance targets for the preceding year. If 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 December 31, 2013, we had accrued $0.4 million 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 is re-determined on a monthly basis. We have guaranteed to Maalt that through December 31, 2014, 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. No payments for non-utilization were required for the years ended December 31, 2013, 2012 or 2011.

Litigation

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. 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.

Self-Insured Reserves

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 $13.6 million, $14.1 million and $12.8 million during the years ended December 31, 2013, 2012 and 2011, respectively.


54
CHESAPEAKE OILFIELD OPERATING, L.L.C.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

7. Share-Based Compensation

Chesapeake’s share-based compensation program consists of restricted stock available to employees and stock options and performance share units (“PSUs”) available to senior management. The restricted stock and stock options are equity-classified awards and the PSUs are liability-classified awards.

Equity-Classified Awards

Restricted Stock. The fair value of 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 $13.2 million, $12.1 million and $10.9 million for the years ended December 31, 2013, 2012 and 2011, 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.
 
 
Number of
Unvested
Restricted Shares
 
Weighted Average
Grant-Date
Fair Value
 
(in thousands)
 
 
Unvested shares as of January 1, 2013
1,840

 
$
23.27

Granted
1,000

 
$
19.21

Vested
(652
)
 
$
23.19

Forfeited
(317
)
 
$
21.32

Unvested shares as of December 31, 2013
1,871

 
$
21.46

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


The aggregate intrinsic value of restricted stock vested for the year ended December 31, 2013, as reflected in the table above, was approximately $12.9 million based on the market price of Chesapeake’s common stock at the time of vesting.

As of December 31, 2013, there was $29.7 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.

Stock Options. During 2013, Chesapeake granted incentive-based and retention-based stock options to a member of COO’s senior management team. The incentive-based stock options will vest ratably over a three-year period and the retention-based stock options will vest one-third on each of the third, fourth and fifth anniversaries of the grant date. The stock option awards have an exercise price equal to the closing price of Chesapeake’s common stock on the grant date. Outstanding options expire ten years from the date of grant.
 

55
CHESAPEAKE OILFIELD OPERATING, L.L.C.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

The following table provides information related to stock option activity for the year ended December 31, 2013:
 
 
Number of
Shares Underlying
Options
 
Weighted Average
Exercise Price
Per Share
 
Weighted Average
Contract  Life
in Years
 
Aggregate
Intrinsic
Value(a)
 
(in thousands)
 
 
 
 
 
(in thousands)
Outstanding at January 1, 2013
—

 
$
—

 
—

 
$
—

Granted
235

 
$
18.97

 
 
 
 
Exercised
—

 
$
—

 
 
 
 
Outstanding at December 31, 2013
235

 
$
18.97

 
9.08

 
$
1,916

Exercisable at December 31, 2013
—

 
$
—

 
 
 
$
—

 
(a)
The intrinsic value of a stock option is the amount by which the current market value or the market value upon exercise of the underlying stock exceeds the exercise price of the option.

As of December 31, 2013, there was $1.3 million of total unrecognized compensation cost related to stock options. The cost is expected to be recognized over a weighted average period of approximately three years.

Liability-Classified Awards

Performance Share Units. In January 2012 and January 2013, Chesapeake granted PSUs to a member of COO’s senior management team under Chesapeake's Long Term Incentive Plan that includes both an internal performance measure and an external market condition. The PSUs can only be settled in cash, so they are classified as a liability in our consolidated financial statements and are measured at fair value as of the grant date and re-measured at fair value 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 December 31, 2013, the fair value of the PSUs was $2.5 million. We have recorded $0.3 million as a short-term liability for PSUs that will be settled in January 2014 and $1.2 million as a long-term liability representing the portion of the award that will be settled in January 2015 or thereafter. The remaining $1.0 million relates to PSUs for which the requisite service period has not been completed.

8. Income Taxes

The components of income tax expense (benefit) for each of the periods presented below are as follows:
 
Years Ended December 31,
 
2013
 
2012
 
2011
 
(in thousands)
Current
$
1,422

 
$
749

 
$
130

Deferred
(9,255
)
 
46,128

 
26,149

Total
$
(7,833
)
 
$
46,877

 
$
26,279



56
CHESAPEAKE OILFIELD OPERATING, L.L.C.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

The effective income tax expense (benefit) differed from the computed “expected” federal income tax expense on earnings before income taxes for the following reasons:
 
Years Ended December 31,
 
2013
 
2012
 
2011
 
(in thousands)
Income tax expense (benefit) at the federal statutory rate (35%)
$
(9,649
)
 
$
40,758

 
$
18,889

State income taxes (net of federal income tax benefit)
677

 
3,859

 
2,265

Acquisition expenditures
—

 
—

 
2,977

Other permanent differences
1,369

 
2,153

 
816

Effect of change in state taxes
—

 
273

 
1,150

Other
(230
)
 
(166
)
 
182

Total
$
(7,833
)
 
$
46,877

 
$
26,279


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:
 
Years Ended December 31,
 
 
2013
 
2012
 
 
(in thousands)
Deferred tax liabilities:
 
 
 
 
Property and equipment
$
(350,662
)
 
$
(294,293
)
 
Deferred gain on sale leaseback
—

 
(27,935
)
 
Intangible assets
(2,801
)
 
(4,291
)
 
Prepaid expenses
(2,697
)
 
(2,115
)
 
Other
(2,584
)
 
(760
)
 
Deferred tax liabilities
(358,744
)
 
(329,394
)
 
 
 
 
 
 
Deferred tax assets:
 
 
 
 
Net operating loss carryforwards
200,200

 
163,386

 
Deferred gain on sale leaseback
802

 
5,783

 
Deferred stock compensation
5,068

 
4,708

 
Accrued liabilities
6,871

 
4,598

 
State tax payments
3,125

 
2,628

 
Other
2,249

 
1,664

 
Deferred tax assets
218,315

 
182,767

 
Net deferred tax liability
$
(140,429
)
 
$
(146,627
)
 
 
 
 
 
 
Reflected in accompanying balance sheets as:
 
 
 
 
Current deferred income tax asset
$
5,318

 
$
3,305

 
Non-current deferred income tax liability
(145,747
)
 
(149,932
)
 
Total
$
(140,429
)
 
$
(146,627
)
 

At December 31, 2013, COO had federal income tax net operating loss (NOL) carryforwards of approximately $531.0 million. Of these carryforwards, $48.5 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 Energy Services Corporation ("Rensco") during

57
CHESAPEAKE OILFIELD OPERATING, L.L.C.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

2011. The NOL carryforwards expire from 2031 through 2033. The value of these carryforwards depends on the ability of COO to generate taxable income.  

9. Investments 

In October 2011, we acquired 49% of the membership interest in Maalt for $12.0 million. We use the equity method of accounting to account for our investment in Maalt, which had a carrying value of $13.2 million as of December 31, 2013. We recorded equity method adjustments to our investment of $0.2 million and $0.1 million for our share of Maalt’s income for the years ended December 31, 2013 and 2012, respectively. We also made additional investments of $0.4 million and $0.5 million during the years ended December 31, 2013 and 2012, respectively. As of December 31, 2013, the carrying value of our investment in Maalt is in excess of the underlying equity in Maalt’s net assets by approximately $12.0 million. This excess is attributable to goodwill recorded on Maalt’s financial statements and is not being 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 that engages in the commercial trucking business.  During 2013, Big Star redeemed our membership interest in exchange for $2.8 million in cash, 30 trailers and the assignment to us of 30 leased trucks from Big Star’s fleet. We recognized a loss of $1.5 million during 2013 related to the redemption, which is included in income (loss) from equity investees on our consolidated statements of operations. Prior to the redemption of our membership interest, we used the equity method of accounting to record our investment in Big Star. We recorded equity method adjustments to our investment of ($1.1) million and $0.5 million for our share of Big Star’s income (loss) for the years ended December 31, 2013 and 2012, respectively.

10. Fair Value Measurements

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.

Fair Value on Recurring Basis

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 on Non-Recurring Basis

Fair value measurements were applied with respect to our non-financial assets and liabilities measured on a non-recurring basis, which consist primarily of long-lived asset impairments based on Level 3 inputs. See Note 2 for additional discussion.
 

58
CHESAPEAKE OILFIELD OPERATING, L.L.C.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

Fair Value of Other Financial Instruments

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.
 
 
December 31, 2013
 
December 31, 2012
 
Carrying
Amount
 
Fair Value
(Level 2)
 
Carrying
Amount
 
Fair Value
(Level 2)
 
(in thousands)
Financial liabilities:
 
 
 
 
 
 
 
Credit Facility
$
405,000

 
$
399,592

 
$
418,200

 
$
401,000

2019 Senior Notes
$
650,000

 
$
679,660

 
$
650,000

 
$
614,250


11. Concentration of Credit Risk and Major Customers

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 $312.5 million and $337.7 million as of December 31, 2013 and December 31, 2012, or 83% and 93%, respectively, of our total accounts receivable. Revenues from Chesapeake and its affiliates were $1.960 billion, $1.811 billion and $1.226 billion for the years ended December 31, 2013, 2012 and 2011, or 90%, 94% and 94%, respectively, of our total revenues. 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.

12. Transactions with Affiliates

In the normal course of business, we provide wellsite services and equipment, including drilling, hydraulic fracturing, oilfield rentals, rig relocation, fluid handling and disposal 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 11).

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.

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 for 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.
 
If 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

59
CHESAPEAKE OILFIELD OPERATING, L.L.C.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

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, that 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 recorded $2.4 million in revenues for non-utilization fees pursuant to the agreement for the year ended December 31, 2013. We did not record any revenues for non-utilization 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 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 facilities lease agreement that cover rent and our proportionate share of maintenance, operating expenses, taxes and insurance. We incurred $16.5 million, $11.8 million and $1.8 million of lease expense for the years ended December 31, 2013, 2012 and 2011, respectively, under this facilities 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 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 multiplying revenues by a percentage determined by Chesapeake based on the historical averages of costs incurred on our behalf. 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 $55.5 million, $49.4 million and $33.7 million for the years ended December 31, 2013, 2012 and 2011, respectively.

We are 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 re-determined on a monthly basis. We have guaranteed to Maalt that through December 31, 2014, 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. No payments for non-utilization were required for the years ended December 31, 2013 or 2012.

13. Segment Information

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, 2013, we owned or leased a fleet of 115 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, 2013, we owned nine hydraulic fracturing fleets with an aggregate of 360,000 horsepower.


60
CHESAPEAKE OILFIELD OPERATING, L.L.C.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

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 December 31, 2013, we owned a fleet of 260 rig relocation trucks, 67 cranes and forklifts and 246 fluid hauling trucks.

Other Operations. Our other operations consist primarily of our natural gas compression unit and related oil and gas production equipment manufacturing business and corporate functions, including our 2019 Senior Notes and Credit Facility.
 

61
CHESAPEAKE OILFIELD OPERATING, L.L.C.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)


 
Drilling
 
Hydraulic
Fracturing
 
Oilfield
Rentals
 
Oilfield
Trucking
 
Other
Operations
 
Intercompany
Eliminations
 
Consolidated
Total
 
(in thousands)
For The Year Ended December 31, 2013:
 
 
 
 
 
 
 
 
 
 
 
 
 
Revenues
$
745,800

 
$
897,809

 
$
161,676

 
$
250,495

 
$
165,500

 
$
(33,075
)
 
$
2,188,205

Intersegment revenues
(4,988
)
 
—

 
(1,435
)
 
(6,115
)
 
(20,537
)
 
33,075

 
—

Total revenues
$
740,812

 
$
897,809

 
$
160,241

 
$
244,380

 
$
144,963

 
$
—

 
$
2,188,205

Depreciation and amortization
133,785

 
69,507

 
59,559

 
25,870

 
870

 
—

 
289,591

Losses (gains) on sales of property and equipment
663

 
—

 
(1,146
)
 
(2,249
)
 
103

 
—

 
(2,629
)
Impairments and other(a)
71,548

 
—

 
1

 
—

 
3,213

 
—

 
74,762

Interest expense
—

 
—

 
—

 
—

 
(56,786
)
 
—

 
(56,786
)
Income (loss) from equity investees
—

 
159

 
—

 
(1,117
)
 
—

 
—

 
(958
)
Other (expense) income
(231
)
 
254

 
1,129

 
184

 
422

 
—

 
1,758

(Loss) Income Before Income Taxes
$
(26,360
)
 
$
67,224

 
$
(2,544
)
 
$
5,555

 
$
(71,443
)
 
$
—

 
$
(27,568
)
Total Assets
$
1,134,026

 
$
454,559

 
$
184,285

 
$
204,386

 
$
55,432

 
$
(5,795
)
 
$
2,026,893

Capital Expenditures
$
284,354

 
$
41,286

 
$
16,925

 
$
3,712

 
$
3,529

 
$
—

 
$
349,806

 
 
 
 
 
 
 
 
 
 
 
 
 
 
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

Losses (gains) on sales of property and equipment
5,526

 
43

 
(3,579
)
 
35

 
—

 
—

 
2,025

Impairments and other(a)
53,621

 
—

 
6,929

 
—

 
160

 
—

 
60,710

Interest expense
—

 
—

 
—

 
—

 
(53,548
)
 
—

 
(53,548
)
Income (loss) 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 (expense) income
(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

(a)
Includes lease termination costs of $22.4 million and $24.9 million for the years ended December 31, 2013 and 2012, respectively.



62
CHESAPEAKE OILFIELD OPERATING, L.L.C.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

14. Condensed Consolidating Financial Information

In October 2011, COO issued and sold the 2019 Senior Notes with an aggregate principal amount of $650.0 million (see Note 4). Pursuant to the Indenture governing the 2019 Senior Notes, such notes are fully and unconditionally and jointly and severally guaranteed by all of COO’s material subsidiaries, other than COF, which is a co-issuer of the 2019 Senior Notes. Each of the subsidiary guarantors is 100% owned by COO and there are no material subsidiaries of COO other than the subsidiary guarantors. COF and WWS are minor non-guarantor subsidiaries whose condensed consolidating financial information is included with the subsidiary guarantors. COO has independent assets and operations. 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, 2013 and December 31, 2012 and for the years ended December 31, 2013, 2012 and 2011. The financial information may not necessarily be indicative of results of operations, cash flows or financial position had the subsidiaries operated as independent entities.
 

63
CHESAPEAKE OILFIELD OPERATING, L.L.C.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

CONDENSED CONSOLIDATING BALANCE SHEET
AS OF DECEMBER 31, 2013
(in thousands)
 
 
Parent
 
Guarantor
Subsidiaries
 
Eliminations
 
Consolidated
Assets:
 
 
 
 
 
 
 
Current Assets:
 
 
 
 
 
 
 
Cash
$
1,615

 
$
63

 
$
—

 
$
1,678

Accounts receivable
—

 
62,959

 
—

 
62,959

Affiliate accounts receivable
1,142

 
311,338

 
—

 
312,480

Inventory
—

 
45,035

 
—

 
45,035

Deferred income tax asset
—

 
5,318

 
—

 
5,318

Prepaid expenses and other
851

 
19,450

 
—

 
20,301

Total Current Assets
3,608

 
444,163

 
—

 
447,771

Property and Equipment:
 
 
 
 
 
 
 
Property and equipment, at cost
3,103

 
2,238,247

 
—

 
2,241,350

Less: accumulated depreciation
(133
)
 
(773,149
)
 
—

 
(773,282
)
Property and equipment held for sale, net
—

 
29,408

 
—

 
29,408

Total Property and Equipment, Net
2,970

 
1,494,506

 
—

 
1,497,476

Other Assets:
 
 
 
 
 
 
 
Investments
—

 
13,236

 
—

 
13,236

Goodwill
—

 
42,447

 
—

 
42,447

Intangible assets, net
—

 
7,429

 
—

 
7,429

Deferred financing costs, net
14,080

 
—

 
—

 
14,080

Other long-term assets
54,958

 
4,454

 
(54,958
)
 
4,454

Investments in subsidiaries and intercompany advances
1,542,365

 
—

 
(1,542,365
)
 
—

Total Other Assets
1,611,403

 
67,566

 
(1,597,323
)
 
81,646

Total Assets
$
1,617,981

 
$
2,006,235

 
$
(1,597,323
)
 
$
2,026,893

Liabilities and Equity:
 
 
 
 
 
 
 
Current Liabilities:
 
 
 
 
 
 
 
Accounts payable
$
2,051

 
$
28,615

 
$
—

 
$
30,666

Affiliate accounts payable
838

 
33,362

 
—

 
34,200

Other current liabilities
11,669

 
198,454

 
—

 
210,123

Total Current Liabilities
14,558

 
260,431

 
—

 
274,989

Long-Term Liabilities:
 
 
 
 
 
 
 
Deferred income tax liabilities
—

 
200,705

 
(54,958
)
 
145,747

Senior notes
650,000

 
—

 
—

 
650,000

Revolving credit facility
405,000

 
—

 
—

 
405,000

Other long-term liabilities
1,231

 
2,734

 
—

 
3,965

Total Long-Term Liabilities
1,056,231

 
203,439

 
(54,958
)
 
1,204,712

Equity
547,192

 
1,542,365

 
(1,542,365
)
 
547,192

Total Liabilities and Equity
$
1,617,981

 
$
2,006,235

 
$
(1,597,323
)
 
$
2,026,893


 

64
CHESAPEAKE OILFIELD OPERATING, L.L.C.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

CONDENSED CONSOLIDATING BALANCE SHEET
AS OF DECEMBER 31, 2012
(in thousands)
 
 
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

Other current 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 long-term 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


 

65
CHESAPEAKE OILFIELD OPERATING, L.L.C.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS
YEAR ENDED DECEMBER 31, 2013
(in thousands)
 
 
Parent
 
Guarantor
Subsidiaries
 
Eliminations
 
Consolidated
Revenues:
 
 
 
 
 
 
 
Revenues
$
8,011

 
$
2,187,966

 
$
(7,772
)
 
$
2,188,205

Operating Expenses:
 
 
 
 
 
 
 
Operating costs
9,513

 
1,717,235

 
(9,039
)
 
1,717,709

Depreciation and amortization
27

 
289,564

 
—

 
289,591

General and administrative
20,506

 
59,848

 
—

 
80,354

Gains on sales of property and equipment
—

 
(2,629
)
 
—

 
(2,629
)
Impairments and other
—

 
74,762

 
—

 
74,762

Total Operating Expenses
30,046

 
2,138,780

 
(9,039
)
 
2,159,787

Operating (Loss) Income
(22,035
)
 
49,186

 
1,267

 
28,418

Other (Expense) Income:
 
 
 
 
 
 
 
Interest expense
(56,786
)
 
—

 
—

 
(56,786
)
Income from equity investees
—

 
(958
)
 
—

 
(958
)
Other expense
—

 
1,758

 
—

 
1,758

Equity in net earnings of subsidiary
29,334

 
—

 
(29,334
)
 
—

Total Other (Expense) Income
(27,452
)
 
800

 
(29,334
)
 
(55,986
)
(Loss) Income Before Income Taxes
(49,487
)
 
49,986

 
(28,067
)
 
(27,568
)
Income Tax (Benefit) Expense
(29,752
)
 
21,439

 
480

 
(7,833
)
Net (Loss) Income
$
(19,735
)
 
$
28,547

 
$
(28,547
)
 
$
(19,735
)

 

66
CHESAPEAKE OILFIELD OPERATING, L.L.C.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS
YEAR ENDED DECEMBER 31, 2012
(in thousands)
 
 
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
—

 
60,710

 
—

 
60,710

Total Operating Expenses
26,118

 
1,731,360

 
(6,275
)
 
1,751,203

Operating (Loss) Income
(21,362
)
 
188,437

 
1,744

 
168,819

Other (Expense) Income:
 
 
 
 
 
 
 
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
116,694

 
—

 
(116,694
)
 
—

Total Other (Expense) Income
63,150

 
1,178

 
(116,694
)
 
(52,366
)
(Loss) Income Before Income Taxes
41,788

 
189,615

 
(114,950
)
 
116,453

Income Tax (Benefit) Expense
(27,788
)
 
74,004

 
661

 
46,877

Net (Loss) Income
$
69,576

 
$
115,611

 
$
(115,611
)
 
$
69,576


 

67
CHESAPEAKE OILFIELD OPERATING, L.L.C.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS
YEAR ENDED DECEMBER 31, 2011
(in thousands)
 
 
Parent
 
Guarantor
Subsidiaries
 
Eliminations
 
Consolidated
Revenues:
 
 
 
 
 
 
 
Revenues
$
—

 
$
1,303,496

 
$
—

 
$
1,303,496

Operating Expenses:
 
 
 
 
 
 
 
Operating costs
2,114

 
984,125

 
—

 
986,239

Depreciation and amortization
—

 
175,790

 
—

 
175,790

General and administrative
728

 
36,346

 
—

 
37,074

Gains on sales of property and equipment
—

 
(3,571
)
 
—

 
(3,571
)
Impairments and other
—

 
2,729

 
—

 
2,729

Total Operating Expenses
2,842

 
1,195,419

 
—

 
1,198,261

Operating (Loss) Income
(2,842
)
 
108,077

 
—

 
105,235

Other (Expense) Income:
 
 
 
 
 
 
 
Interest expense
(8,766
)
 
(40,036
)
 
—

 
(48,802
)
Other income
(1,063
)
 
(1,401
)
 
—

 
(2,464
)
Equity in net earnings of subsidiary
36,045

 
—

 
(36,045
)
 
—

Total Other (Expense) Income
26,216

 
(41,437
)
 
(36,045
)
 
(51,266
)
(Loss) Income Before Income Taxes
23,374

 
66,640

 
(36,045
)
 
53,969

Income Tax (Benefit) Expense
(4,316
)
 
30,595

 
—

 
26,279

Net Income (Loss)
27,690

 
36,045

 
(36,045
)
 
27,690

Less: Net Loss Attributable to Noncontrolling Interest (1)
—

 
—

 
(154
)
 
(154
)
Net Income (Loss) Attributable to Chesapeake Oilfield Operating, L.L.C.
$
27,690

 
$
36,045

 
$
(35,891
)
 
$
27,844


 (1)
The net loss attributable to noncontrolling interest is the result of our consolidation of Rensco, which was merged into Nomac Services during 2011.


 

68
CHESAPEAKE OILFIELD OPERATING, L.L.C.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS
YEAR ENDED DECEMBER 31, 2013
(in thousands)
 
 
Parent
 
Guarantor
Subsidiaries
 
Eliminations
 
Consolidated
Cash Flows From Operating Activities:
$
13,766

 
$
404,170

 
$
(80,865
)
 
$
337,071

Cash Flows From Investing Activities:
 
 
 
 
 
 
 
Additions to property and equipment
(3,103
)
 
(346,703
)
 
—

 
(349,806
)
Proceeds from sale of assets
—

 
50,602

 
—

 
50,602

Proceeds from sale of investment
—

 
2,790

 
—

 
2,790

Additions to investments
—

 
(431
)
 
—

 
(431
)
Other
—

 
28

 
—

 
28

Cash used in investing activities
(3,103
)
 
(293,714
)
 
—

 
(296,817
)
Cash Flows From Financing Activities:
 
 
 
 
 
 
 
Contributions from (distributions to) affiliates
—

 
(110,755
)
 
80,865

 
(29,890
)
Borrowings from revolving credit facility
1,216,900

 
—

 
—

 
1,216,900

Payments on revolving credit facility
(1,230,100
)
 
—

 
—

 
(1,230,100
)
Other
3,287

 
—

 
—

 
3,287

Net cash provided by (used in) financing activities
(9,913
)
 
(110,755
)
 
80,865

 
(39,803
)
Net increase (decrease) in cash
750

 
(299
)
 
—

 
451

Cash, beginning of period
863

 
364

 
—

 
1,227

Cash, end of period
$
1,613

 
$
65

 
$
—

 
$
1,678


 

69
CHESAPEAKE OILFIELD OPERATING, L.L.C.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS
YEAR ENDED DECEMBER 31, 2012
(in thousands)
 
 
 
 
Guarantor
 
 
 
Parent
 
Subsidiaries
 
Eliminations
 
Consolidated
Cash Flows From Operating Activities:
$
(73,940
)
 
$
285,091

 
$
—

 
$
211,151

Cash Flows From Investing Activities:
 
 
 
 
 
 
 
Additions to property and equipment
—

 
(622,825
)
 
—

 
(622,825
)
Proceeds from sale of assets
—

 
47,421

 
—

 
47,421

Additions to investments
(314,397
)
 
(1,920
)
 
314,397

 
(1,920
)
Cash used in investing activities
(314,397
)
 
(577,324
)
 
314,397

 
(577,324
)
Cash Flows From Financing Activities:
 
 
 
 
 
 
 
Contributions from (distributions to) affiliates
—

 
292,067

 
(314,397
)
 
(22,330
)
Borrowings from revolving credit facility
1,389,100

 
—

 
—

 
1,389,100

Payments on revolving credit facility
(999,900
)
 
—

 
—

 
(999,900
)
Net cash provided by financing activities
389,200

 
292,067

 
(314,397
)
 
366,870

Net increase in cash
863

 
(166
)
 
—

 
697

Cash, beginning of period
—

 
530

 
—

 
530

Cash, end of period
$
863

 
$
364

 
$
—

 
$
1,227



70
CHESAPEAKE OILFIELD OPERATING, L.L.C.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS
YEAR ENDED DECEMBER 31, 2011
(in thousands)
 
 
 
 
Guarantor
 
 
 
Parent
 
Subsidiaries
 
Eliminations
 
Consolidated
Cash Flows From Operating Activities:
$
(793
)
 
$
240,839

 
$
—

 
$
240,046

Cash Flows From Investing Activities:
 
 
 
 
 
 
 
Additions to property and equipment
—

 
(412,753
)
 
—

 
(412,753
)
Acquisition of business
—

 
(339,962
)
 
—

 
(339,962
)
Proceeds from sale of assets
—

 
110,902

 
—

 
110,902

Additions to investments
(658,039
)
 
(16,657
)
 
658,039

 
(16,657
)
Cash used in investing activities
(658,039
)
 
(658,470
)
 
658,039

 
(658,470
)
Cash Flows From Financing Activities:
 
 
 
 
 
 
 
Contributions from (distributions to) affiliates
—

 
1,111,205

 
(658,039
)
 
453,166

Decrease in affiliate debt
—

 
(635,070
)
 
—

 
(635,070
)
Borrowings from revolving credit facility
168,000

 
—

 
—

 
168,000

Payments on revolving credit facility
(139,000
)
 
—

 
—

 
(139,000
)
Proceeds from issuance of senior notes, net of offering costs
637,000

 
—

 
—

 
637,000

Deferred financing costs
(7,168
)
 
—

 
—

 
(7,168
)
Payments on third-party notes
—

 
(55,213
)
 
—

 
(55,213
)
Acquisition of noncontrolling interest
—

 
(3,131
)
 
—

 
(3,131
)
Net cash provided by financing activities
658,832

 
417,791

 
(658,039
)
 
418,584

Net increase in cash
—

 
160

 
—

 
160

Cash, beginning of period
—

 
370

 
—

 
370

Cash, end of period
$
—

 
$
530

 
$
—

 
$
530



71
CHESAPEAKE OILFIELD OPERATING, L.L.C.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

15. Quarterly Financial Data (unaudited)

Summarized unaudited quarterly financial data for 2013 and 2012 are as follows:

 
Quarters Ended
 
March 31, 2013
 
June 30, 2013
 
September 30, 2013
 
December 31, 2013
 
(in thousands)
Revenues
$
543,887

 
$
583,064

 
$
550,403

 
$
510,851

Operating income (loss)(a)
$
37,837

 
$
27,297

 
$
(16,336
)
 
$
(20,380
)
Net income (loss)(a)
$
14,233

 
$
7,176

 
$
(18,684
)
 
$
(22,460
)
 
 
 
 
 
 
 
 
 
Quarters Ended
 
March 31, 2012
 
June 30, 2012
 
September 30, 2012
 
December 31, 2012
 
(in thousands)
Revenues
$
446,881

 
$
504,806

 
$
486,781

 
$
481,554

Operating income(a)
$
50,846

 
$
73,616

 
$
14,173

 
$
30,184

Net income (loss)(a)
$
22,836

 
$
37,265

 
$
(206
)
 
$
9,681


(a)
Includes $44.4 million and $23.6 million of impairments and other for the quarters ended December 31, 2013 and September 30, 2013, respectively. Includes $30.7 million and $21.9 million of impairments and other for the quarters ended September 30, 2012 and June 30, 2012, respectively.

16. Recently Issued and Proposed Accounting Standards

Recently Issued Accounting Standards

To reduce diversity in practice related to the presentation of unrecognized tax benefits, in July 2013 the Financial Accounting Standards Board ("FASB") issued guidance requiring the presentation of an unrecognized tax benefit in the financial statements as a reduction to a deferred tax asset for a net operating loss carryforward, a similar tax loss or a tax credit carryforward. This net presentation is required unless a net operating loss carryforward, a similar tax loss or a tax credit carryforward is not available at the reporting date or the tax law of the jurisdiction does not require, and the entity does not intend to use, the deferred tax asset to settle any additional income tax that would result from the disallowance of the unrecognized tax benefit. The guidance was effective on January 1, 2014. The adoption of this standard did not have a material impact on our consolidated financial statements.

17. Subsequent Events

Subsequent to December 31, 2013, we purchased 14 leased drilling rigs subject to the master lease agreements described in Note 6. In conjunction with the purchases, we also terminated approximately $29.0 million of remaining lease commitments associated with these drilling rigs. Total consideration paid was approximately $62.3 million.

On February 24, 2014, Chesapeake announced that it was pursuing strategic alternatives for COO, including a potential spin-off to Chesapeake shareholders or an outright sale.

72

Item 9.
Changes In and Disagreements with Accountants on Accounting and Financial Disclosure
 
 
 

Not applicable.

Item 9A.
Controls and Procedures
 
 
 

Disclosure Controls and Procedures

As required by Rule 13a-15(b) and 15d-15(b) of the Securities Exchange Act of 1934, as amended (the “Exchange Act”), we have evaluated, under the supervision and with the participation of our management, including our principal executive officer and principal financial officer, the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act) as of the end of the period covered by this report. Our disclosure controls and procedures are designed to provide reasonable assurance that the information required to be disclosed by us in reports that we file under the Exchange Act is accumulated and communicated to our management, including our principal executive officer and principal financial officer, as appropriate, and is recorded, processed, summarized and reported within the time periods specified in the rules and forms of the SEC. Based upon the evaluation, our principal executive officer and principal financial officer have concluded that our disclosure controls and procedures were effective as of December 31, 2013 at the reasonable assurance level.

Changes in Internal Control Over Financial Reporting

There was no change in our internal control over financial reporting during the year ended December 31, 2013 which materially affected, or was reasonably likely to materially affect, our internal control over financial reporting.

Management's Report on Internal Control Over Financial Reporting

This annual report does not include a report of management’s assessment regarding internal control over financial reporting or an attestation report of the company’s registered public accounting firm due to a transition period established by rules of the Securities and Exchange Commission for newly public companies.

Item 9B.
Other Information
 
 
 

Not applicable.

73

PART III

Item 10.
Directors, Executive Officers and Corporate Governance
 
 
 

The information called for by Item 10 is omitted pursuant to Instruction I(2) to Form 10-K (Omission of Information by Certain Wholly Owned Subsidiaries).

Item 11.
Executive Compensation
 
 
 

The information called for by Item 11 is omitted pursuant to Instruction I(2) to Form 10-K (Omission of Information by Certain Wholly Owned Subsidiaries).

Item 12.
Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters
 
 
 

The information called for by Item 12 is omitted pursuant to Instruction I(2) to Form 10-K (Omission of Information by Certain Wholly Owned Subsidiaries).

Item 13.
Certain Relationships and Related Transactions and Director Independence
 
 
 

Master Services Agreement

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

Services Agreement

We are a party to a services agreement with Chesapeake under which Chesapeake guarantees the utilization of a portion of our drilling rig and hydraulic fracturing fleets during the term of the agreement. Chesapeake guarantees that it will operate, on a daywork basis at market-based rates, the lesser of 75 of our drilling rigs or 80% of our operational drilling rig fleet, each referred to as a “committed rig,” subject to ratable reduction for each of our drilling rigs that is operated by a third-party customer. In addition, Chesapeake guarantees that each month it will utilize a number of our operational hydraulic fracturing fleets, up to a maximum of 13 fleets, to complete a minimum aggregate number of fracturing stages equal to 25 stages per month at market-based rates, times the average number of our operational hydraulic fracturing fleets during such month, each referred to as a “committed stage,” subject to ratable reduction for each stage that we perform for a third-party customer during such month. In the event Chesapeake does not meet either the 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.

74


Administrative Services Agreement

Chesapeake provides us with general and administrative services and the services of its employees pursuant to an administrative services agreement. In return for the general and administrative services provided by Chesapeake, we reimburse Chesapeake on a monthly basis for the overhead expenses incurred by Chesapeake on our behalf in accordance with its current allocation policy, which includes actual out-of-pocket fees, costs and expenses incurred in connection with the provision of any of the services under the agreement, including the allocable portion of the wages and benefits of Chesapeake employees who perform services on our behalf. The administrative services agreement has a five-year initial term ending October 25, 2016 and will thereafter automatically extend for successive one-year terms unless we or Chesapeake give written notice of termination at least one year prior to the end of a term.

Facilities Lease Agreement

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

Related Party Transactions

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.

Corporate Governance

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.


75

Item 14.
Principal Accountant Fees and Services
 
 
 

The aggregate fees billed by PricewaterhouseCoopers LLP, the Company's independent registered public accountants, for the years ended December 31, 2013, 2012 and 2011 were as follows:

 
Years Ended December 31,
 
2013
 
2012
 
2011
 
(in thousands)
Audit Fees(a)
$
980

 
$
750

 
$
1,127

Audit-Related Fees
—

 
—

 
—

Tax Fees
—

 
—

 
—

All Other Fees
—

 
—

 
—

Total Fees for Services Provided
$
980

 
$
750

 
$
1,127

(a)
Fees for 2013 include $950,000 related to the 2013 audit and interim reviews and $30,000 related to services provided in connection with our registration of debt securities. Fees for 2012 relate to the 2012 audit and interim reviews. Fees for 2011 include $1,032,000 related to 2008 through 2011 audits and $95,000 related to services provided in connection with our issuance of debt securities.

COO is not required to have, and does not have, an audit committee.    

76

PART IV

Item 15.
Exhibits, Financial Statement Schedules
 
 
 

The following exhibits are filed as a part of this report:
 
 
 
 
 
Incorporated by Reference
 
 
 
 
Exhibit
Number
 
Exhibit Description
 
Form
 
Commission
File No.
 
Exhibit
 
Filing Date
 
Filed
Herewith
 
Furnished
Herewith
3.1

 
Articles of Organization of Chesapeake Oilfield Operating, L.L.C.
 
S-4
 
333-187766
 
3.1

 
5/30/2013
 
 
 
 
3.2

 
Operating Agreement of Chesapeake Oilfield Operating, L.L.C.
 
S-4
 
333-187766
 
3.2

 
5/30/2013
 
 
 
 
3.3

 
Certificate of Incorporation of Chesapeake Oilfield Finance, Inc.
 
S-4
 
333-187766
 
3.3

 
5/30/2013
 
 
 
 
3.4

 
Bylaws of Chesapeake Oilfield Finance, Inc.
 
S-4
 
333-187766
 
3.4

 
5/30/2013
 
 
 
 
4.1

 
Credit Agreement, dated as of November 3, 2011, among Chesapeake Oilfield Operating, L.L.C., the lenders party thereto and Bank of America, N.A., as administrative agent and collateral agent
 
S-4
 
333-187766
 
4.1

 
5/30/2013
 
 
 
 
4.2

 
First Amendment to Credit Agreement, dated as of April 12, 2012, among Chesapeake Oilfield Operating, L.L.C., the lenders party thereto and Bank of America, N.A., as administrative agent and collateral agent
 
S-4
 
333-187766
 
4.2

 
5/30/2013
 
 
 
 
4.3

 
Second Amendment to Credit Agreement, dated as of December 18, 2012, among Chesapeake Oilfield Operating, L.L.C., the lenders party thereto and Bank of America, N.A., as administrative agent and collateral agent
 
S-4
 
333-187766
 
4.3

 
5/30/2013
 
 
 
 
4.4

 
Third Amendment to Credit Agreement, dated as of November 21, 2013, among Chesapeake Oilfield Operating, L.L.C., the lenders party thereto and Bank of America, N.A., as administrative agent and collateral agent
 
 
 
 
 
 
 
 
 
X
 
 
4.5

 
Indenture, dated as of October 28, 2011, among Chesapeake Oilfield Operating, L.L.C., Chesapeake Oilfield Finance, Inc., the guarantors named therein and The Bank of New York Mellon Trust Company, N.A., as trustee
 
S-4
 
333-187766
 
4.4

 
5/30/2013
 
 
 
 
4.6

 
Form of 6.625% Senior Note due 2019
 
S-4
 
333-187766
 
4.5

 
5/30/2013
 
 
 
 
10.1

 
Master Services Agreement, dated as of October 25, 2011, between COS Holdings, L.L.C. and Chesapeake Operating, Inc.
 
S-4
 
333-187766
 
10.1

 
5/30/2013
 
 
 
 
10.2

 
Services Agreement, dated as of October 25, 2011, between COS Holdings, L.L.C. and Chesapeake Operating, Inc.
 
S-4
 
333-187766
 
10.2

 
5/30/2013
 
 
 
 

77

10.3

 
Administrative Services Agreement, dated as of October 25, 2011, between COS Holdings, L.L.C. and Chesapeake Operating, Inc.
 
S-4
 
333-187766
 
10.3

 
5/30/2013
 
 
 
 
10.4

 
Master Lease Agreement, dated as of January 1, 2012, between Chesapeake Land Development Company L.L.C. and Chesapeake Oilfield Operating, L.L.C.
 
S-4
 
333-187766
 
10.4

 
5/30/2013
 
 
 
 
10.5

 
Employment Agreement dated as of September 15, 2011 between Jerry L. Winchester and Chesapeake Energy Corporation
 
S-4
 
333-187766
 
10.5

 
5/30/2013
 
 
 
 
10.6

 
First Amendment to Employment Agreement dated as of November 9, 2011 between Jerry L. Winchester and Chesapeake Energy Corporation
 
S-4
 
333-187766
 
10.6

 
5/30/2013
 
 
 
 
10.7

 
Second Amendment to Employment Agreement dated as of December 22, 2011 between Jerry L. Winchester and Chesapeake Energy Corporation
 
S-4
 
333-187766
 
10.7

 
5/30/2013
 
 
 
 
10.8

 
Employment Agreement dated as of January 9, 2012 between Cary D. Baetz and COS Holdings, L.L.C.
 
S-4
 
333-187766
 
10.8

 
5/30/2013
 
 
 
 
12.1

 
Schedule of Computation of Ratio of Earnings to Fixed Charges
 
 
 
 
 
 
 
 
 
X
 
 
31.1

 
Certification of Chief Executive Officer pursuant to Rule 13(a)-14 and 15(d)-14 under the Securities Exchange Act of 1934
 
 
 
 
 
 
 
 
 
X
 
 
31.2

 
Certification of Chief Financial Officer pursuant to Rule 13(a)-14 and 15(d)-14 under the Securities Exchange Act of 1934
 
 
 
 
 
 
 
 
 
X
 
 
32.1

 
Certification of Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
 
 
 
 
 
 
 
 
 
 
 
X
32.2

 
Certification of Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
 
 
 
 
 
 
 
 
 
 
 
X
101.1

 
Interactive data files pursuant to Rule 405 of Regulation S-T
 
 
 
 
 
 
 
 
 
 
 
†
 
†
Pursuant to Rule 406T of Regulation S-T, interactive data files are deemed not filed or part of a registration statement or prospectus for purposes of sections 11 and 12 of the Securities Act of 1933, are deemed not filed for purposes of Section 18 of the Securities Exchange Act of 1934 and otherwise are not subject to any liability under those sections.


78

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
CHESAPEAKE OILFIELD OPERATING, L.L.C.
Date: March 14, 2014                    By:    /s/ Jerry L. Winchester            
Jerry L. Winchester
Chief Executive Officer

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.
Signature
 
Capacity
 
Date
/s/ Jerry L. Winchester
 
Chief Executive Officer
(Principal Executive Officer)
 
March 14, 2014
Jerry L. Winchester
 
 
 
 
 
/s/ Cary D. Baetz
 
Chief Financial Officer
(Principal Financial Officer and
Principal Accounting Officer)
 
March 14, 2014
Cary D. Baetz



79

INDEX TO EXHIBITS
 
 
 
 
Incorporated by Reference
 
 
 
 
Exhibit
Number
 
Exhibit Description
 
Form
 
Commission
File No.
 
Exhibit
 
Filing Date
 
Filed
Herewith
 
Furnished
Herewith
3.1

 
Articles of Organization of Chesapeake Oilfield Operating, L.L.C.
 
S-4
 
333-187766
 
3.1

 
5/30/2013
 
 
 
 
3.2

 
Operating Agreement of Chesapeake Oilfield Operating, L.L.C.
 
S-4
 
333-187766
 
3.2

 
5/30/2013
 
 
 
 
3.3

 
Certificate of Incorporation of Chesapeake Oilfield Finance, Inc.
 
S-4
 
333-187766
 
3.3

 
5/30/2013
 
 
 
 
3.4

 
Bylaws of Chesapeake Oilfield Finance, Inc.
 
S-4
 
333-187766
 
3.4

 
5/30/2013
 
 
 
 
4.1

 
Credit Agreement, dated as of November 3, 2011, among Chesapeake Oilfield Operating, L.L.C., the lenders party thereto and Bank of America, N.A., as administrative agent and collateral agent
 
S-4
 
333-187766
 
4.1

 
5/30/2013
 
 
 
 
4.2

 
First Amendment to Credit Agreement, dated as of April 12, 2012, among Chesapeake Oilfield Operating, L.L.C., the lenders party thereto and Bank of America, N.A., as administrative agent and collateral agent
 
S-4
 
333-187766
 
4.2

 
5/30/2013
 
 
 
 
4.3

 
Second Amendment to Credit Agreement, dated as of December 18, 2012, among Chesapeake Oilfield Operating, L.L.C., the lenders party thereto and Bank of America, N.A., as administrative agent and collateral agent
 
S-4
 
333-187766
 
4.3

 
5/30/2013
 
 
 
 
4.4

 
Third Amendment to Credit Agreement, dated as of November 21, 2013, among Chesapeake Oilfield Operating, L.L.C., the lenders party thereto and Bank of America, N.A., as administrative agent and collateral agent
 
 
 
 
 
 
 
 
 
X
 
 
4.5

 
Indenture, dated as of October 28, 2011, among Chesapeake Oilfield Operating, L.L.C., Chesapeake Oilfield Finance, Inc., the guarantors named therein and The Bank of New York Mellon Trust Company, N.A., as trustee
 
S-4
 
333-187766
 
4.4

 
5/30/2013
 
 
 
 
4.6

 
Form of 6.625% Senior Note due 2019
 
S-4
 
333-187766
 
4.5

 
5/30/2013
 
 
 
 
10.1

 
Master Services Agreement, dated as of October 25, 2011, between COS Holdings, L.L.C. and Chesapeake Operating, Inc.
 
S-4
 
333-187766
 
10.1

 
5/30/2013
 
 
 
 
10.2

 
Services Agreement, dated as of October 25, 2011, between COS Holdings, L.L.C. and Chesapeake Operating, Inc.
 
S-4
 
333-187766
 
10.2

 
5/30/2013
 
 
 
 
10.3

 
Administrative Services Agreement, dated as of October 25, 2011, between COS Holdings, L.L.C. and Chesapeake Operating, Inc.
 
S-4
 
333-187766
 
10.3

 
5/30/2013
 
 
 
 
10.4

 
Master Lease Agreement, dated as of January 1, 2012, between Chesapeake Land Development Company L.L.C. and Chesapeake Oilfield Operating, L.L.C.
 
S-4
 
333-187766
 
10.4

 
5/30/2013
 
 
 
 

80

10.5

 
Employment Agreement dated as of September 15, 2011 between Jerry L. Winchester and Chesapeake Energy Corporation
 
S-4
 
333-187766
 
10.5

 
5/30/2013
 
 
 
 
10.6

 
First Amendment to Employment Agreement dated as of November 9, 2011 between Jerry L. Winchester and Chesapeake Energy Corporation
 
S-4
 
333-187766
 
10.6

 
5/30/2013
 
 
 
 
10.7

 
Second Amendment to Employment Agreement dated as of December 22, 2011 between Jerry L. Winchester and Chesapeake Energy Corporation
 
S-4
 
333-187766
 
10.7

 
5/30/2013
 
 
 
 
10.8

 
Employment Agreement dated as of January 9, 2012 between Cary D. Baetz and COS Holdings, L.L.C.
 
S-4
 
333-187766
 
10.8

 
5/30/2013
 
 
 
 
12.1

 
Schedule of Computation of Ratio of Earnings to Fixed Charges
 
 
 
 
 
 
 
 
 
X
 
 
31.1

 
Certification of Chief Executive Officer pursuant to Rule 13(a)-14 and 15(d)-14 under the Securities Exchange Act of 1934
 
 
 
 
 
 
 
 
 
X
 
 
31.2

 
Certification of Chief Financial Officer pursuant to Rule 13(a)-14 and 15(d)-14 under the Securities Exchange Act of 1934
 
 
 
 
 
 
 
 
 
X
 
 
32.1

 
Certification of Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
 
 
 
 
 
 
 
 
 
 
 
X
32.2

 
Certification of Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
 
 
 
 
 
 
 
 
 
 
 
X
101.1

 
Interactive data files pursuant to Rule 405 of Regulation S-T
 
 
 
 
 
 
 
 
 
 
 
†

 
†
Pursuant to Rule 406T of Regulation S-T, interactive data files are deemed not filed or part of a registration statement or prospectus for purposes of sections 11 and 12 of the Securities Act of 1933, are deemed not filed for purposes of Section 18 of the Securities Exchange Act of 1934 and otherwise are not subject to any liability under those sections.

81