PATTERSON UTI ENERGY INC - Annual Report: 2012 (Form 10-K)

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-K

(Mark One)

For the fiscal year ended December 31, 2012

or

For the transition period from                      to                     

Commission File Number 0-22664

Patterson-UTI Energy, Inc.

(Exact name of registrant as specified in its charter)

Registrant’s telephone number, including area code:

(281) 765-7100

Securities Registered Pursuant to Section 12(b) of the Act:

Securities Registered Pursuant to Section 12(g) of the Act:

None

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

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

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  þ        No  ¨

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Website, 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  þ        or 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 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.  þ

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

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

The aggregate market value of the voting and non-voting common equity held by non-affiliates of the registrant as of June 29, 2012, the last business day of the registrant’s most recently completed second fiscal quarter, was approximately $2.2 billion, calculated by reference to the closing price of $14.56 for the common stock on the Nasdaq Global Select Market on that date.

As of February 8, 2013, the registrant had outstanding 145,925,594 shares of common stock, $0.01 par value, its only class of common stock.

Documents incorporated by reference:

Portions of the registrant’s definitive proxy statement for the 2013 Annual Meeting of Stockholders are incorporated by reference into Part III of this report.

DISCLOSURE REGARDING FORWARD-LOOKING STATEMENTS

This Annual Report on Form 10-K (this “Report”) and other public filings and press releases by us contain “forward-looking statements” within the meaning of the Securities Act of 1933, as amended (the “Securities Act”), the Securities Exchange Act of 1934, as amended (the “Exchange Act”), and the Private Securities Litigation Reform Act of 1995, as amended. These “forward-looking statements” involve risk and uncertainty. These forward-looking statements include, without limitation, statements relating to: liquidity; revenue expectations and backlog; financing of operations; continued volatility of oil and natural gas prices; source and sufficiency of funds required for building new equipment and additional acquisitions (if further opportunities arise); impact of inflation; demand for our services; and other matters. Our forward-looking statements can be identified by the fact that they do not relate strictly to historic or current facts and often use words such as “believes,” “budgeted,” “continue,” “expects,” “estimates,” “project,” “will,” “could,” “may,” “plans,” “intends,” “strategy,” or “anticipates,” or the negative thereof and other words and expressions of similar meaning. The forward-looking statements are based on certain assumptions and analyses we make in light of our experience and our perception of historical trends, current conditions, expected future developments and other factors we believe are appropriate in the circumstances. Although we believe that the expectations reflected in such forward-looking statements are reasonable, we can give no assurance that such expectations will prove to have been correct. Forward-looking statements may be made orally or in writing, including, but not limited to, Management’s Discussion and Analysis of Financial Condition and Results of Operations included in this Report and other sections of our filings with the United States Securities and Exchange Commission (the “SEC”) under the Exchange Act and the Securities Act.

Forward-looking statements are not guarantees of future performance and a variety of factors could cause actual results to differ materially from the anticipated or expected results expressed in or suggested by these forward-looking statements. Factors that might cause or contribute to such differences include, but are not limited to, global economic conditions, volatility in customer spending and in oil and natural gas prices that could adversely affect demand for our services and their associated effect on rates, utilization, margins and planned capital expenditures, excess availability of land drilling rigs and pressure pumping equipment, including as a result of reactivation or construction, adverse industry conditions, adverse credit and equity market conditions, difficulty in integrating acquisitions, shortages of labor, equipment, supplies and materials, weather, loss of key customers, liabilities from operations for which we do not have and receive full indemnification or insurance, governmental regulation and ability to retain management and field personnel. Refer to “Risk Factors” contained in Item 1A of this Report for a more complete discussion of these and other factors that might affect our performance and financial results. You are cautioned not to place undue reliance on any of our forward-looking statements. These forward-looking statements are intended to relay our expectations about the future, and speak only as of the date they are made. We undertake no obligation to publicly update or revise any forward-looking statement, whether as a result of new information, changes in internal estimates or otherwise, except as required by law.

PART I

Available Information

This Report, along with our Quarterly Reports on Form 10-Q, Current Reports on Form 8-K and amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Exchange Act, are available free of charge through our internet website (www.patenergy.com) as soon as reasonably practicable after we electronically file such material with, or furnish it to, the SEC. The information contained on our website is not part of this Report or other filings that we make with the SEC. You may read and copy any materials we file with the SEC at the SEC’s Public Reference Room at 100 F Street, NE, Washington, DC 20549. You may obtain information on the operation

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of the Public Reference Room by calling the SEC at 1-800-SEC-0330. The SEC maintains an internet site (www.sec.gov) that contains reports, proxy and information statements and other information regarding issuers that file electronically with the SEC.

Overview

We own and operate one of the largest fleets of land-based drilling rigs in the United States. The Company was formed in 1978 and reincorporated in 1993 as a Delaware corporation. Our contract drilling business operates in the continental United States, Alaska, and western and northern Canada.

As of December 31, 2012, we had a drilling fleet that consisted of 314 marketable land-based drilling rigs. A drilling rig includes the structure, power source and machinery necessary to cause a drill bit to penetrate the earth to a depth desired by the customer. A drilling rig is considered marketable at a point in time if it is operating or can be made ready to operate without significant capital expenditures. We also have a substantial inventory of drill pipe and drilling rig components.

We provide pressure pumping services to oil and natural gas operators primarily in Texas and the Appalachian Basin. Pressure pumping services consist primarily of well stimulation and cementing for completion of new wells and remedial work on existing wells.

We also own and invest in oil and natural gas assets as a non-operating working interest owner. Our oil and natural gas working interests are located primarily in Texas and New Mexico.

Prior to January 20, 2010, we provided drilling fluids, completion fluids and related services to oil and natural gas operators offshore in the Gulf of Mexico and on land in Texas, New Mexico, Oklahoma and Louisiana. We sold our drilling and completion fluids services business on January 20, 2010. On October 1, 2010, we acquired the assets and operations of a pressure pumping business and an electric wireline business. The electric wireline business that we acquired was classified as held for sale at December 31, 2010 and sold on January 27, 2011. The results of our drilling and completion fluids services business and our electric wireline business are presented as discontinued operations in this Report.

Industry Segments

Our revenues, operating profits and identifiable assets are primarily attributable to three industry segments:

All of our industry segments had operating profits in 2012, 2011 and 2010.

See “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and Note 15 of Notes to Consolidated Financial Statements included as a part of Items 7 and 8, respectively, of this Report for financial information pertaining to these industry segments.

Contract Drilling Operations

General — We market our contract drilling services to major and independent oil and natural gas operators. As of December 31, 2012, we had 314 marketable land-based drilling rigs based in the following regions:

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Our marketable drilling rigs have rated maximum depth capabilities ranging from 5,250 feet to 25,000 feet. Of these drilling rigs, 167 are electric rigs and 147 are mechanical rigs. An electric rig differs from a mechanical rig in that the electric rig converts the power from its engines (the sole energy source for a mechanical rig) into electricity to power the rig. We also have a substantial inventory of drill pipe and drilling rig components, which may be used in the activation of additional drilling rigs or as replacement parts for marketable rigs.

Drilling rigs are typically equipped with engines, drawworks, masts, pumps to circulate the drilling fluid, blowout preventers, drill pipe and other related equipment. Over time, components on a drilling rig are replaced or rebuilt. We spend significant funds each year as part of a program to modify, upgrade and maintain our drilling rigs to ensure that our drilling equipment is competitive. We have spent over $2.2 billion during the last three years on capital expenditures to (1) build new land drilling rigs and (2) modify, upgrade and extend the lives of components of our drilling fleet. During fiscal years 2012, 2011 and 2010, we spent approximately $745 million, $785 million and $656 million, respectively, on these capital expenditures.

Depth and complexity of the well and drill site conditions are the principal factors in determining the specifications of the rig selected for a particular job.

Our contract drilling operations depend on the availability of drill pipe, drill bits, replacement parts and other related rig equipment, fuel and other materials and qualified personnel. Some of these have been in short supply from time to time.

Drilling Contracts — Most of our drilling contracts are with established customers on a competitive bid or negotiated basis. Our drilling contracts are either on a well-to-well basis or a term basis. Well-to-well contracts are generally short-term in nature and cover the drilling of a single well or a series of wells. Term contracts are entered into for a specified period of time (frequently six months to three years) and provide for the use of the drilling rig to drill multiple wells. During 2012, our average number of days to drill a well (which includes moving to the drill site, rigging up and rigging down) was approximately 22 days.

Our drilling contracts obligate us to provide and operate a drilling rig and to pay certain operating expenses, including wages of our drilling personnel and necessary maintenance expenses. Most drilling contracts are subject to termination by the customer on short notice and may or may not contain provisions for an early termination payment to us in the event that the contract is terminated by the customer. We believe that our drilling contracts generally provide for indemnification rights and obligations that are customary for the markets in which we conduct those operations; however, each drilling contract contains the actual terms setting forth our rights and obligations and those of the customer, any of which rights and obligations may deviate from what is customary due to particular industry conditions, customer requirements or other factors.

Our drilling contracts provide for payment on a daywork, footage or turnkey basis, or a combination thereof. In each case, we provide the rig and crews. Our bid for each job depends upon location, depth and anticipated complexity of the well, on-site drilling conditions, equipment to be used, estimated risks involved, estimated duration of the job, availability of drilling rigs and other factors particular to each proposed well.

Under daywork contracts, we provide the drilling rig and crew to the customer. The customer supervises the drilling of the well. Our compensation is based on a contracted rate per day during the period the drilling rig is utilized. We often receive a lower rate when the drilling rig is moving or when drilling operations are interrupted or restricted by adverse weather conditions or other conditions beyond our control. Daywork contracts typically provide separately for mobilization of the drilling rig. All of the wells we drilled in 2012, 2011 and 2010 were under daywork contracts.

Under footage contracts, we contract to drill a well to a certain depth under specified conditions for a fixed price per foot. The customer provides drilling fluids, casing, cementing and well design expertise. These contracts require us to bear the cost of services and supplies that we provide until the well has been drilled to the

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agreed-upon depth. If we drill the well in less time than estimated, we have the opportunity to improve our profits over those that would be attainable under a daywork contract. Profits are reduced and losses may be incurred if the well requires more days to drill to the contracted depth than estimated. Footage contracts generally contain greater risks for a drilling contractor than daywork contracts. Under footage contracts, the drilling contractor typically assumes certain risks associated with loss of the well from fire, blowouts and other risks. Although we have entered into footage contracts in the past, we did not drill any wells under footage contracts in the past three years.

Under turnkey contracts, we contract to drill a well to a certain depth under specified conditions for a fixed fee. In a turnkey arrangement, we are required to bear the costs of services, supplies and equipment beyond those typically provided under a footage contract. In addition to the drilling rig and crew, we are required to provide the drilling and completion fluids, casing, cementing, and the technical well design and engineering services during the drilling process. We also typically assume certain risks associated with drilling the well such as fires, blowouts, cratering of the well bore and other such risks. Compensation occurs only when the agreed-upon scope of the work has been completed, which requires us to make larger up-front working capital commitments prior to receiving payments under a turnkey drilling contract. Under a turnkey contract, we have the opportunity to improve our profits if the drilling process goes as expected and there are no complications or time delays. Given the increased exposure we have under a turnkey contract, however, profits can be significantly reduced and losses can be incurred if complications or delays occur during the drilling process. Turnkey contracts generally involve the highest degree of risk among the three different types of drilling contracts. Although we have entered into turnkey contracts in the past, we did not drill any wells under turnkey contracts in the past three years.

Contract Drilling Activity — Information regarding our contract drilling activity for the last three years follows:

Drilling Rigs and Related Equipment — We have made significant upgrades during the last several years to our drilling fleet to match the needs of our customers. While conventional wells remain an important source of natural gas and oil, our customers have expanded the development of shale and other unconventional wells to help supply the long-term demand for natural gas and oil in North America.

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To address our customers’ needs for drilling wells in the newer horizontal shale and other unconventional resource plays, we have expanded our areas of operation and improved the capability of our drilling fleet. We have delivered new APEX^® rigs to the market and have made performance and safety improvements to existing high capacity rigs. APEX 1500^® rigs are 1,500 horsepower electric rigs with advanced electronic drilling systems, 500 ton top drives, iron roughnecks, hydraulic catwalks, and other highly automated pipe handling equipment. APEX 1000^® rigs are 1,000 horsepower electric rigs with advanced technology equipment similar to the APEX 1500^® rigs, but with a more compact design to fit on smaller locations. APEX WALKING^® rigs are designed to efficiently drill multiple wells from a single pad, by “walking” between the wellbores without requiring time to lower the mast and lay down the drill pipe. Some APEX 1500^® and APEX 1000^® rigs have also been equipped with walking systems. As of December 31, 2012 our drilling fleet was comprised of the following:

We estimate the depth capacity with respect to our marketable rigs as of December 31, 2012 to be as follows:

At December 31, 2012, we owned and operated 312 trucks and 410 trailers used to rig down, transport and rig up our drilling rigs. Our ownership of trucks and trailers reduces our dependency upon third parties for these services and generally enhances the efficiency of our contract drilling operations in periods of high drilling rig utilization.

We perform repair and overhaul work to our drilling rig equipment at our yard facilities located in Texas, Oklahoma, Wyoming, Colorado, Pennsylvania and western Canada.

Pressure Pumping Operations

General — We provide pressure pumping services to oil and natural gas operators primarily in Texas (Southwest Region) and the Appalachian Basin (Northeast Region). Pressure pumping services consist of well stimulation and cementing for the completion of new wells and remedial work on existing wells. Wells drilled in shale formations and other unconventional plays require well stimulation through fracturing to allow the flow of oil and natural gas. This is accomplished by pumping fluids under pressure into the well bore to fracture the formation. Many wells in conventional plays also receive well stimulation services. The cementing process inserts material between the wall of the well bore and the casing to support and stabilize the casing.

Pressure Pumping Contracts — Our pressure pumping operations are conducted pursuant to a work order for a specific job or pursuant to a term contract. The term contracts are generally entered into for a specified

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period of time and may include minimum revenue, usage or stage requirements. We are compensated based on a combination of charges for equipment, personnel, materials, mobilization and other items. We believe that our pressure pumping contracts generally provide for indemnification rights and obligations that are customary for the markets in which we conduct those operations; however, each pressure pumping contract contains the actual terms setting forth our rights and obligations and those of the customer, any of which rights and obligations may deviate from what is customary due to particular industry conditions, customer requirements or other factors.

Equipment — We have pressure pumping equipment used in providing hydraulic and nitrogen fracturing services as well as nitrogen, cementing and acid pumping services, with a total of approximately 758,000 hydraulic horsepower as of December 31, 2012. Pressure pumping equipment at December 31, 2012 included:

Our pressure pumping operations are supported by a fleet of other equipment including blenders, tractors, manifold trailers and numerous trailers for transportation of materials to and from the worksite as well as bins for storage of materials at the worksite.

Materials — Our pressure pumping operations require the use of acids, chemicals, proppants, fluid supplies and other materials, any of which can be in short supply, including severe shortages, from time to time. We purchase these materials from various suppliers. These purchases are made in the spot market or pursuant to other arrangements that do not cover all of our required supply and that sometimes require us to purchase the supply or pay liquidated damages if we do not purchase the material. Given the limited number of suppliers of certain of our materials, we may not always be able to make alternative arrangements if we are unable to reach an agreement with a supplier for delivery of any particular material or should one of our suppliers fail to timely deliver our materials.

Oil and Natural Gas Interests

We own and invest in oil and natural gas assets as a non-operating working interest owner. Our oil and natural gas working interests are located primarily in producing regions of Texas and New Mexico. Our oil and natural gas assets constituted approximately 1% of our consolidated assets as of December 31, 2012.

Customers

The customers of each of our contract drilling and pressure pumping business segments are oil and natural gas operators. Our customer base includes both major and independent oil and natural gas operators. During 2012, no single customer accounted for 10% or more of our consolidated operating revenues.

Competition

Our contract drilling and pressure pumping businesses are highly competitive. Historically, available equipment used in these businesses has frequently exceeded demand. The price for our services is a key competitive factor, in part because equipment used in our businesses can be moved from one area to another in response to market conditions. In addition to price, we believe availability, condition and technical specifications

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of equipment, quality of personnel, service quality and safety record are key factors in determining which contractor is awarded a job. We expect that the market for land drilling and pressure pumping services will continue to be highly competitive.

Government and Environmental Regulation

All of our operations and facilities are subject to numerous federal, state, foreign, and local laws, rules and regulations related to various aspects of our business, including:

To date, applicable environmental laws and regulations in the United States and Canada have not required the expenditure of significant resources outside the ordinary course of business. We do not anticipate any material capital expenditures for environmental control facilities or extraordinary expenditures to comply with environmental rules and regulations in the foreseeable future. However, compliance costs under existing laws or under any new requirements could become material, and we could incur liability in any instance of noncompliance.

Our business is generally affected by political developments and by federal, state, foreign, and local laws, rules and regulations that relate to the oil and natural gas industry. The adoption of laws, rules and regulations affecting the oil and natural gas industry for economic, environmental and other policy reasons could increase costs relating to drilling, completion and production, and otherwise have an adverse effect on our operations. Federal, state, foreign and local environmental laws, rules and regulations currently apply to our operations and may become more stringent in the future. Any suspension or moratorium of the services we provide, whether or not short-term in nature, by a federal, state, foreign or local governmental authority, could have a material adverse effect on our business, financial condition and results of operation.

We believe we use operating and disposal practices that are standard in the industry. However, hydrocarbons and other materials may have been disposed of, or released in or under properties currently or formerly owned or operated by us or our predecessors, which may have resulted, or may result, in soil and groundwater contamination in certain locations. Any contamination found on, under or originating from the properties may be subject to remediation requirements under federal, state, foreign and local laws, rules and regulations. In addition, some of these properties have been operated by third parties over whom we have no control of their treatment of hydrocarbon and other materials or the manner in which they may have disposed of or released such materials. We could be required to remove or remediate wastes disposed of or released by prior owners or operators. In addition, it is possible we could be held responsible for oil and natural gas properties in which we own an interest but are not the operator.

Some of the environmental laws and regulations that are applicable to our business operations are discussed in the following paragraphs, but the discussion does not cover all environmental laws and regulations that govern our operations.

In the United States, the Federal Comprehensive Environmental Response Compensation and Liability Act of 1980, as amended, commonly known as CERCLA, and comparable state statutes impose strict liability on:

The Federal Resource Conservation and Recovery Act (“RCRA”), as amended, and comparable state statutes govern the disposal of “hazardous wastes.” Although CERCLA currently excludes petroleum from the definition of “hazardous substances,” and RCRA also excludes certain classes of exploration and production

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wastes from regulation, such exemptions by Congress under both CERCLA and RCRA may be deleted, limited, or modified in the future. If such changes are made to CERCLA and/or RCRA, we could be required to remove and remediate previously disposed of materials (including materials disposed of or released by prior owners or operators) from properties (including ground water contaminated with hydrocarbons) and to perform removal or remedial actions to prevent future contamination.

The Federal Water Pollution Control Act and the Oil Pollution Act of 1990, as amended, and implementing regulations govern:

The Oil Pollution Act imposes strict liability for a comprehensive and expansive list of damages from an oil spill into waters from facilities. Liability may be imposed for oil removal costs and a variety of public and private damages. Penalties may also be imposed for violation of federal safety, construction and operating regulations, and for failure to report a spill or to cooperate fully in a clean-up.

The Oil Pollution Act also expands the authority and capability of the federal government to direct and manage oil spill clean-up and operations, and requires operators to prepare oil spill response plans in cases where it can reasonably be expected that substantial harm will be done to the environment by discharges on or into navigable waters. Failure to comply with ongoing requirements or inadequate cooperation during a spill event may subject a responsible party, such as us, to civil or criminal actions. Although the liability for owners and operators is the same under the Federal Water Pollution Act, the damages recoverable under the Oil Pollution Act are potentially much greater and can include natural resource damages.

Our activities include the performance of hydraulic fracturing services to enhance the production of oil and natural gas from formations with low permeability, such as shales and other unconventional formations. Due to concerns raised relating to potential impacts of hydraulic fracturing on groundwater quality, legislative and regulatory efforts at the federal level and in some states have been initiated to render permitting and compliance requirements more stringent for hydraulic fracturing or prohibit the activity altogether. Such efforts could have an adverse effect on oil and natural gas production activities, which in turn could have an adverse effect on the hydraulic fracturing services that we render for our exploration and production customers. See “Item 1A. Risk Factors — Potential Legislation and Regulation Covering Hydraulic Fracturing Could Increase Our Costs and Limit or Delay Our Operations.”

In Canada, a variety of Canadian federal, provincial and municipal laws, rules and regulations impose, among other things, restrictions, liabilities and obligations in connection with the generation, handling, use, storage, transportation, treatment and disposal of hazardous substances and wastes and in connection with spills, releases and emissions of various substances to the environment. These laws, rules and regulations also require that facility sites and other properties associated with our operations be operated, maintained, abandoned and reclaimed to the satisfaction of applicable regulatory authorities. In addition, new projects or changes to existing projects may require the submission and approval of environmental assessments or permit applications. These laws, rules and regulations are subject to frequent change, and the clear trend is to place increasingly stringent limitations on activities that may affect the environment.

Our operations are also subject to federal, state, foreign and local laws, rules and regulations for the control of air emissions, including the Federal Clean Air Act and the Canadian Environmental Protection Act. We and our customers may be required to make capital expenditures in the future for air pollution control equipment in connection with obtaining and maintaining operating permits and approvals for air emissions. For example, on August 16, 2012, the U.S. Environmental Protection Agency (“EPA”) published final rules that establish new air emission control requirements for natural gas and NGL production, processing and transportation activities, including New Source Performance Standards (“NSPS”) and National Emissions Standards for Hazardous Air Pollutants (“NESHAP”) that impose, among other things, new standards for completions of hydraulically fractured natural gas wells. For more information, please refer to our discussion under “Item 1A. Risk Factors — Environmental Laws and Regulations, Including Violations Thereof, Could Materially Adversely Affect Our Operating Results.”

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We are aware of the increasing focus of local, state, national and international regulatory bodies on greenhouse gas (“GHG”) emissions and climate change issues. We are also aware of legislation proposed by United States lawmakers and the Canadian legislature to reduce GHG emissions, as well as GHG emissions regulations enacted by the EPA and the Canadian provinces of Alberta and British Columbia. We will continue to monitor and assess any new policies, legislation or regulations in the areas where we operate to determine the impact of GHG emissions and climate change on our operations and take appropriate actions, where necessary. Any direct and indirect costs of meeting these requirements may adversely affect our business, results of operations and financial condition. See “Item 1A. Risk Factors — Legislation and Regulation of Greenhouse Gases Could Adversely Affect Our Business.”

Risks and Insurance

Our operations are subject to many hazards inherent in the contract drilling and pressure pumping businesses, including inclement weather, blowouts, well fires, loss of well control, pollution and reservoir damage. These hazards could cause personal injury or death, work stoppage, and serious damage to equipment and other property, as well as significant environmental and reservoir damages. These risks could expose us to substantial liability for personal injury, wrongful death, property damage, loss of oil and natural gas production, pollution and other environmental damages.

We have indemnification agreements with many of our customers, and we also maintain liability and other forms of insurance. In general, our drilling and pressure pumping contracts typically contain provisions requiring our customer to indemnify us for, among other things, reservoir and certain pollution damage. Our right to indemnification may, however, be unenforceable or limited due to negligent or willful acts or omissions by us, our subcontractors and/or suppliers. Our customers may dispute, or be unable to meet, their contractual indemnification obligations to us due to financial, legal or other reasons. Accordingly, we may be unable to transfer these risks to our customers by contract or indemnification agreements. Incurring a liability for which we are not fully indemnified or insured could have a material adverse effect on our business, financial condition, cash flows and results of operations.

We maintain insurance coverage of types and amounts that we believe to be customary for our businesses, but we are not fully insured against all risks, either because insurance is not available or because of the high premium costs. The insurance coverage that we maintain includes insurance for fire, windstorm and other risks of physical loss to our rigs and certain other assets, employer’s liability, automobile liability, commercial general liability insurance, workers’ compensation and insurance for other specific risks. We cannot assure, however, that any insurance obtained by us will be adequate to cover any losses or liabilities, or that this insurance will continue to be available or available on terms that are acceptable to us. While we carry insurance to cover physical damage to, or loss of, our drilling rigs and certain other assets, such insurance does not cover the full replacement cost of the rigs or other assets. We have also elected in some cases to accept a greater amount of risk through increased deductibles on certain insurance policies. For example, we generally maintain a $1.0 million per occurrence deductible on our workers’ compensation and equipment insurance coverage and a $2.0 million per occurrence self-insured retention on our general liability insurance coverage. We self-insure a number of other risks, including loss of earnings and business interruption, and do not carry a significant amount of insurance to cover risks of underground reservoir damage.

Our insurance will not in all situations provide sufficient funds to protect us from all liabilities that could result from our operations. Our coverage includes aggregate policy limits and exclusions. As a result, we retain the risk for any loss in excess of these limits or that is otherwise excluded from our coverage. There can be no assurance that insurance will be available to cover any or all of our operational risks, or, even if available, that insurance premiums or other costs will not rise significantly in the future, so as to make the cost of such insurance prohibitive or that our coverage will cover a specific loss. Further, we may experience difficulties in collecting from insurers or such insurers may deny all or a portion of our claims for insurance coverage.

If a significant accident or other event occurs and is not fully covered by insurance or an enforceable or recoverable indemnity from a third party, it could have a material adverse effect on our business, financial

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condition, cash flows and results of operations. See “Item 1A. Risk Factors – Our Operations Are Subject to a Number of Operational Risks, Including Environmental and Weather Risks, Which Could Expose Us to Significant Losses and Damage Claims. We Are Not Fully Insured Against All of These Risks and Our Contractual Indemnity Provisions May Not Fully Protect Us.”

Employees

We had approximately 7,300 full-time employees at December 31, 2012. The number of employees fluctuates depending on the current and expected demand for our services. We consider our employee relations to be satisfactory. None of our employees are represented by a union.

Seasonality

Seasonality has not significantly affected our overall operations. However, our drilling operations in Canada and, to a lesser extent, our pressure pumping operations in the Appalachian Basin, are subject to slow periods of activity during the annual Spring thaw.

Raw Materials and Subcontractors

We use many suppliers of raw materials and services. Although these materials and services have historically been available, there is no assurance that such materials and services will continue to be available on favorable terms or at all. We also utilize numerous independent subcontractors from various trades.

You should consider each of the following factors as well as the other information in this Report in evaluating our business and our prospects. Additional risks and uncertainties not presently known to us or that we currently consider immaterial may also impair our business operations. If any of the following risks actually occur, our business, financial condition, cash flows and results of operations could be harmed. You should also refer to the other information set forth in this Report, including our consolidated financial statements and the related notes.

Global Economic Conditions May Adversely Affect Our Operating Results.

Global economic conditions and volatility in commodity prices may cause our customers to reduce or curtail their drilling and well completion programs, which could result in a decrease in demand for our services. In addition, uncertainty in the capital markets may result in reduced access to financing by our customers and reduced demand for our services. Furthermore, these factors may result in certain of our customers experiencing an inability to pay suppliers, including us. Although the significant deterioration in the global economic environment appeared to stabilize to some degree since 2009, there is no assurance that the global economic environment will not quickly deteriorate again due to one or more factors. A deterioration in the global economic environment could have a material adverse effect on our business, financial condition, cash flows and results of operations.

We Are Dependent on the Oil and Natural Gas Industry and Market Prices for Oil and Natural Gas. Declines in Customers’ Operating and Capital Expenditures and in Oil and Natural Gas Prices May Adversely Affect Our Operating Results.

We depend on our customers’ willingness to make operating and capital expenditures to explore for, develop and produce oil and natural gas in North America. If these expenditures decline, our business may suffer. Our customers’ willingness to explore, develop and produce depends largely upon prevailing industry conditions that are influenced by numerous factors over which we have no control, such as:

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In particular, our revenue, profitability and cash flows are highly dependent upon prevailing prices for oil and natural gas and expectations about future prices. For many years, oil and natural gas prices and markets have been extremely volatile. Prices are affected by factors such as:

All of these factors are beyond our control. During the second quarter of 2008, the quarterly average market price of natural gas (Henry Hub spot price as reported by the Energy Information Administration) was $11.74 per Mcf and the quarterly average market price of oil (WTI spot price as reported by the Energy Information Administration) was $123.95 per barrel. In the last half of 2008, commodity prices rapidly declined and averaged $6.60 per Mcf for natural gas and $58.35 per barrel for oil in the fourth quarter of 2008. In 2009, the price of natural gas declined further and averaged $4.06 per Mcf for the year. Oil prices remained depressed during 2009 as well and averaged $61.65 per barrel for the year. These declines in the market prices of natural gas and oil caused our customers to significantly reduce their drilling activities beginning in the fourth quarter of 2008, and drilling activities remained low throughout 2009. Drilling activities increased in 2010 as did the prices for oil and natural gas. The increased drilling activity was largely attributable to increased development of unconventional oil and natural gas reservoirs and an improvement in the price of oil which averaged $79.40 per barrel in 2010. Drilling for oil and liquids rich targets continued to increase in 2011 as oil averaged $94.86 per barrel for the year. Natural gas prices decreased in 2011 to an average of $4.00 per Mcf. The 2011 decrease in natural gas prices was most significant in the fourth quarter where the average price dropped to $3.32 per Mcf. This decrease continued into 2012 where natural gas prices fell below $2.00 per Mcf in April and averaged $2.75 per Mcf for the year, resulting in continued low levels of drilling activity for natural gas in 2012. The increase in drilling activity in oil rich basins absorbed some of the decrease in demand for natural gas drilling activities in 2012. Our average number of rigs operating remains well below the number of our available rigs. Construction of new land drilling rigs in the United States during the last decade has significantly contributed to excess capacity in total available drilling rigs. As a result of decreased drilling activity and excess capacity, our average number of rigs operating has declined from historic highs. We expect oil and natural gas prices to continue to be volatile and to affect our financial condition, operations and ability to access sources of capital. Low market prices for oil and natural gas would likely result in lower demand for our drilling rigs and pressure pumping services and could adversely affect our operating results, financial condition and cash flows. Even during periods of high prices for oil and natural gas, companies exploring for oil and natural gas may cancel or curtail programs, or reduce their levels of capital expenditures for exploration and production for a variety of reasons, which could reduce demand for our drilling rigs and pressure pumping services.

A General Excess of Operable Land Drilling Rigs, Increasing Rig Specialization and Excess Pressure Pumping Equipment May Adversely Affect Our Utilization and Profit Margins.

The North American oil and natural gas services industry has experienced downturns in demand during the last decade. During these periods, there have been substantially more drilling rigs and pressure pumping equipment available than necessary to meet demand. As a result, drilling and pressure pumping contractors have had difficulty sustaining profit margins and, at times, have incurred losses during the downturn periods.

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In addition, unconventional resource plays have substantially increased and some drilling rigs are not capable of drilling these wells efficiently. Accordingly, the utilization of some older technology drilling rigs may be hampered by their lack of capability to successfully compete for this work. Other ongoing factors which could continue to adversely affect utilization rates and pricing, even in an environment of high oil and natural gas prices and increased drilling activity, include:

Construction of new technology drilling rigs has increased in recent years. The addition of new technology drilling rigs to the market, combined with a reduction in the drilling of vertical wells, has resulted in excess capacity of conventional drilling rigs. Similarly, the substantial recent increase in unconventional resource plays has led to higher demand for pressure pumping services and there has been a significant increase in the construction of new pressure pumping equipment across the industry. As a result of low natural gas prices and the construction of new equipment, there is currently an excess of pressure pumping equipment available. In circumstances of excess capacity, providers of pressure pumping services have difficulty sustaining profit margins and may sustain losses during downturn periods. We cannot predict the future level of demand for our contract drilling or pressure pumping services or future conditions in the oil and natural gas contract drilling or pressure pumping businesses.

Shortages of Drill Pipe, Replacement Parts, Other Equipment, Supplies and Materials Adversely Affect Our Operating Results.

During periods of increased demand for drilling and pressure pumping services, the industry has experienced shortages of drill pipe, replacement parts, other equipment, supplies and materials, including, in the case of our pressure pumping operations, proppants, acid, gel and water. These shortages can cause the price of these items to increase significantly and require that orders for the items be placed well in advance of expected use. In addition, any interruption in supply could result in significant delays in delivery of equipment and materials or prevent operations. Interruptions may be caused by, among other reasons:

These price increases, delays in delivery and interruptions in supply may require us to increase capital and repair expenditures and incur higher operating costs. Severe shortages, delays in delivery and interruptions in supply could limit our ability to construct and operate our drilling rigs and pressure pumping equipment and could have a material adverse effect on our business, financial condition, cash flows and results of operations.

Fixed Term Contracts May in Certain Instances Be Terminated Without an Early Termination Payment.

Fixed term drilling contracts customarily provide for termination at the election of the customer, with an “early termination payment” to us if a contract is terminated prior to the expiration of the fixed term. However, in certain circumstances, for example, destruction of a drilling rig that is not replaced within a specified period of time, our bankruptcy, or a breach of our contract obligations, no early termination payment may be paid to us. Additionally, during depressed market conditions or otherwise, customers may be unable to satisfy their contractual obligations or may seek to terminate, renegotiate or fail to honor their contractual obligations. The failure to receive an early termination payment under a number of our fixed-term contracts could have a material adverse effect on our business, financial condition, cash flows and results of operations.

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The Oil Service Business Segments in Which We Operate Are Highly Competitive with Excess Capacity, which Adversely Affects Our Operating Results.

Our land drilling and pressure pumping businesses are highly competitive. At times, available land drilling rigs and pressure pumping equipment exceed the demand for such equipment. This excess capacity has resulted in substantial competition for drilling and pressure pumping contracts. The fact that drilling rigs and pressure pumping equipment are mobile and can be moved from one market to another in response to market conditions heightens the competition in the industry.

We believe that price competition for drilling and pressure pumping contracts will continue to be intense due to the existence of available rigs and pressure pumping equipment. As a result of competition, our utilization may decrease and/or we may be unable to maintain or increase prices for our services, which could have a material adverse effect on our business, financial condition, cash flows and results of operations.

Labor Shortages and Rising Labor Costs Adversely Affect Our Operating Results.

During periods of increasing demand for contract drilling and pressure pumping services, the industry experiences shortages of qualified personnel. During these periods, our ability to attract and retain sufficient qualified personnel to market and operate our drilling rigs and pressure pumping equipment is adversely affected, which negatively impacts both our operations and profitability. Operationally, it is more difficult to hire qualified personnel, which adversely affects our ability to mobilize inactive rigs and pressure pumping equipment in response to the increased demand for such services. Additionally, wage rates for drilling and pressure pumping personnel are likely to increase during periods of increasing demand, resulting in higher operating costs.

The Loss of Large Customers Could Have a Material Adverse Effect on Our Financial Condition and Results of Operations.

In 2012, we received approximately 40% of our consolidated operating revenues from our ten largest customers and approximately 25% of our consolidated operating revenues from our five largest customers. Although no single customer accounted for more than approximately seven percent of our consolidated operating revenue in 2012, the loss of one or more of our larger customers could have a material adverse effect on our business, financial condition, cash flows and results of operations.

Growth Through the Building of New Rigs and Pressure Pumping Equipment and Rig and Other Acquisitions Are Not Assured.

We have increased our drilling rig fleet and pressure pumping horsepower in the past through mergers, acquisitions and new construction. There can be no assurance that acquisition opportunities will be available in the future. We are also likely to continue to face intense competition from other companies for available acquisition opportunities. In addition, because improved technology has enhanced the ability to recover oil and natural gas, contract drillers may continue to build new, high technology rigs and providers of pressure pumping services may continue to build new, high horsepower equipment.

There can be no assurance that we will:

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We may incur substantial indebtedness to finance future acquisitions, build new drilling rigs or build new pressure pumping equipment and also may issue equity, convertible or debt securities in connection with any such acquisitions or building program. Debt service requirements could represent a significant burden on our results of operations and financial condition, and the issuance of additional equity or convertible securities could be dilutive to existing stockholders. Also, continued growth could strain our management, operations, employees and other resources.

Our Operations Are Subject to a Number of Operational Risks, Including Environmental and Weather Risks, Which Could Expose Us to Significant Losses and Damage Claims. We Are Not Fully Insured Against All of These Risks and Our Contractual Indemnity Provisions May Not Fully Protect Us.

Our operations are subject to many hazards inherent in the contract drilling and pressure pumping businesses, including inclement weather, blowouts, well fires, loss of well control, pollution and reservoir damage. These hazards could cause personal injury or death, work stoppage, and serious damage to equipment and other property, as well as significant environmental and reservoir damages. These risks could expose us to substantial liability for personal injury, wrongful death, property damage, loss of oil and natural gas production, pollution and other environmental damages.

We have indemnification agreements with many of our customers, and we also maintain liability and other forms of insurance. In general, our drilling and pressure pumping contracts typically contain provisions requiring our customers to indemnify us for, among other things, reservoir and certain pollution damage. Our right to indemnification may, however, be unenforceable or limited due to negligent or willful acts or omissions by us, our subcontractors and/or suppliers. Our customers may dispute, or be unable to meet, their indemnification obligations to us due to financial, legal or other reasons. Accordingly, we may be unable to transfer these risks to our customers by contract or indemnification agreements. Incurring a liability for which we are not fully indemnified or insured could have a material adverse effect on our business, financial condition, cash flows and results of operations.

We maintain insurance coverage of types and amounts that we believe to be customary in the industry, but we are not fully insured against all risks, either because insurance is not available or because of the high premium costs. The insurance coverage that we maintain includes insurance for fire, windstorm and other risks of physical loss to our rigs and certain other assets, employer’s liability, automobile liability, commercial general liability insurance, workers’ compensation and insurance for other specific risks. We cannot assure, however, that any insurance obtained by us will be adequate to cover any losses or liabilities, or that this insurance will continue to be available or available on terms that are acceptable to us. While we carry insurance to cover physical damage to, or loss of, our drilling rigs and certain other assets, such insurance does not cover the full replacement cost of the rigs or other assets. We have also elected in some cases to accept a greater amount of risk through increased deductibles on certain insurance policies. For example, we generally maintain a $1.0 million per occurrence deductible on our workers’ compensation and equipment insurance coverage and a $2.0 million per occurrence self-insured retention on our general liability insurance coverage. We self-insure a number of other risks, including loss of earnings and business interruption, and do not carry a significant amount of insurance to cover risks of underground reservoir damage.

Our insurance will not in all situations provide sufficient funds to protect us from all liabilities that could result from our operations. Our coverage includes aggregate policy limits and exclusions. As a result, we retain the risk for any loss in excess of these limits or that is otherwise excluded from our coverage. There can be no assurance that insurance will be available to cover any or all of our operational risks, or, even if available, that insurance premiums or other costs will not rise significantly in the future, so as to make the cost of such insurance prohibitive or that our coverage will cover a specific loss. Further, we may experience difficulties in collecting from insurers or such insurers may deny all or a portion of our claims for insurance coverage. Incurring a liability for which we are not fully insured or indemnified could materially adversely affect our business, financial condition, cash flows and results of operations.

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If a significant accident or other event occurs and is not fully covered by insurance or an enforceable or recoverable indemnity from a third party, it could have a material adverse effect on our business, financial condition, cash flows and results of operations.

New Technologies, Process Improvements and Other Factors May Cause Our Drilling and Pressure Pumping Processes and Equipment to Become Less Competitive and Oil and Natural Gas Wells to be Drilled and Completed More Quickly, Resulting in an Adverse Effect on our Financial Condition and Results of Operations.

Changes in technology or improvements in competitors’ processes and equipment could make our processes and equipment less competitive or require significant capital expenditures to keep our processes and equipment competitive. In addition, technological changes, process improvements and other factors that increase operational efficiencies could result in oil and natural gas wells being drilled and completed more quickly, which could reduce the number of revenue earning days. Any such changes in technology could have a material adverse effect on our business, financial condition, cash flows and results of operations.

Environmental Laws and Regulations, Including Violations Thereof Could Materially Adversely Affect Our Operating Results.

All of our operations and facilities are subject to numerous federal, state, foreign and local environmental laws, rules and regulations, including, without limitation, laws concerning the containment and disposal of hazardous substances, oil field waste and other waste materials, the use of underground storage tanks, and the use of underground injection wells. The cost of compliance with these laws and regulations could be substantial. A failure to comply with these requirements could expose us to substantial civil and criminal penalties. In addition, environmental laws and regulations in the United States and Canada impose a variety of requirements on “responsible parties” related to the prevention of oil spills and liability for damages from such spills. As an owner and operator of land-based drilling rigs and pressure pumping equipment, we may be deemed to be a responsible party under these laws and regulations.

Changes in environmental laws and regulations occur frequently and such laws and regulations tend to become more stringent over time. Stricter laws, regulations or enforcement policies could significantly increase compliance costs for us and our customers and have a material adverse effect on our operations or financial position. For example, on August 16, 2012, the EPA issued final rules that establish new air emission control requirements for natural gas and NGL production, processing and transportation activities, including NSPS to address emissions of sulfur dioxide and volatile organic compounds and NESHAPS to address hazardous air pollutants frequently associated with gas production and processing activities. 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 now required to use completion combustion device equipment (i.e., flaring) if emissions cannot be directed to a gathering line. Further, the final rules under NESHAPS 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. These rules may require the implementation of new operating standards which may impact our business. If these or other initiatives result in an increase in regulation, it could increase costs to us and our customers or reduce demand for our services, which could have a material adverse effect on our business, financial condition, cash flows and results of operations.

Potential Legislation and Regulation Covering Hydraulic Fracturing Could Increase Our Costs and Limit or Delay Our Operations.

Members of the U.S. Congress and the EPA are reviewing more stringent regulation of hydraulic fracturing, a technology employed by our pressure pumping business, which involves the injection of water, sand and chemicals under pressure into rock formations to stimulate oil and natural gas production. Both the EPA and the U.S. Congress are studying whether there is any link between hydraulic fracturing activities and soil or ground

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water contamination. As part of their respective studies, the House Subcommittee on Energy and Environment and the EPA each sent requests to a number of companies, including our company, for information on their hydraulic fracturing practices. We have responded to each of the inquiries. In addition, legislation has been proposed in the U.S. Congress to amend the Federal Safe Drinking Water Act to require the disclosure of chemicals used by the oil and gas industry in the hydraulic fracturing process, which could make it easier for third parties opposing the hydraulic fracturing process to initiate legal proceedings based on allegations that specific chemicals used in the fracturing process are impairing ground water or causing other damage. These bills, if adopted, could establish an additional level of regulation at the federal or state level that could limit or delay operational activities or increase operating costs and could result in additional regulatory burdens that could make it more difficult to perform or limit hydraulic fracturing and increase our costs of compliance and doing business. Certain states where we operate, including Texas, have adopted or are considering similar disclosure legislation. For example, Colorado, North Dakota, Montana, Texas, Louisiana, and Wyoming have adopted a variety of well construction, set back and disclosure regulations limiting how fracturing can be performed and requiring various degrees of chemical disclosure. In addition, the EPA has asserted federal regulatory authority over hydraulic fracturing involving diesel additives under the Safe Drinking Water Act’s Underground Injection Control Program and is developing guidance documents related to this newly asserted regulatory authority. Additional regulation could increase the costs of conducting our business and could materially reduce our business opportunities and revenues if our customers decrease their levels of activity in response to such regulation.

A number of federal agencies are analyzing, or have been requested to review a variety of environmental issues associated with hydraulic fracturing. For example, the EPA is conducting a study of the potential environmental effects of hydraulic fracturing on drinking water and groundwater. The EPA released a progress report on December 21, 2012 outlining work currently underway and is expected to release results of the study in 2014. In addition, the EPA announced on October 20, 2011 that it is launching a study of wastewater resulting from hydraulic fracturing activities and currently plans to propose pretreatment regulations by 2014. These ongoing or proposed studies, depending on their course, and any meaningful results obtained, could spur initiatives to further regulate hydraulic fracturing under the Safe Drinking Water Act or other regulatory mechanism.

The adoption of any future federal or state laws or implementing regulations imposing reporting obligations on, or otherwise limiting, the hydraulic fracturing process could make it more difficult to perform hydraulic fracturing and could increase our costs of compliance and doing business and reduce demand for our services. Regulation that significantly restricts or prohibits hydraulic fracturing could have a material adverse impact on our business, financial condition, cash flows and results of operations.

Legislation and Regulation of Greenhouse Gases Could Adversely Affect our Business

We are aware of the increasing focus of local, state, national and international regulatory bodies on GHG emissions and climate change issues. We are also aware of legislation proposed by United States lawmakers and the Canadian legislature to reduce GHG emissions, as well as GHG emissions regulations enacted by the EPA and the Canadian provinces of Alberta and British Columbia. In December 2009, the EPA determined that emissions of carbon dioxide, methane and other GHG present a danger to public health and the environment because emissions of such gases are, according to the EPA, contributing to the warming of the earth’s atmosphere and other climatic changes. Based on its findings, the EPA has begun adopting and implementing regulations to restrict emissions of GHGs under existing provisions of the Federal Clean Air Act, including one regulation that requires a reduction in emissions of GHGs from motor vehicles and another that regulates emissions of GHGs from certain large sources. In addition, the EPA published rules requiring reporting of GHG emissions from specified large GHG emission sources in the United States on an annual basis, which has been amended to include certain onshore and offshore oil and natural gas production facilities. In addition, 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. We will continue to monitor and assess any new policies, legislation or regulations in the areas where we operate to determine the

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impact of GHG emissions and climate change on our operations and take appropriate actions, where necessary. Any direct and indirect costs of meeting these requirements may adversely affect our business, results of operations and financial condition. Because our business depends on the level of activity in the oil and natural gas industry, existing or future laws or regulations related to GHGs and climate change, including incentives to conserve energy or use alternative energy sources, could have a negative impact on our business if such laws or regulations reduce demand for oil and natural gas.

We Are Dependent Upon our Subsidiaries to Meet our Obligations Under our Long Term Debt

We have borrowings outstanding under our senior notes, term loan facility and, from time to time, revolving credit facility. These obligations are guaranteed by each of our existing subsidiaries other than immaterial subsidiaries. Our ability to meet our interest and principal payment obligations depends in large part on dividends paid to us by our subsidiaries. If our subsidiaries do not generate sufficient cash flows to pay us dividends, we may be unable to meet our interest and principal payment obligations.

Variable Rate Indebtedness Subjects Us to Interest Rate Risk, Which Could Cause Our Debt Service Obligations to Increase Significantly.

We have in place a committed senior unsecured credit facility that includes a revolving credit facility and a term loan facility. Interest is paid on the outstanding principal amount of borrowings under the credit facility at a floating rate based on, at our election, LIBOR or a base rate. The margin on LIBOR loans ranges from 2.25% to 3.25% and the margin on base rate loans ranges from 1.25% to 2.25%, based on our debt to capitalization ratio. At December 31, 2012, the margin on LIBOR loans was 2.25% and the margin on base rate loans was 1.25%. As of December 31, 2012, we had no borrowings outstanding under our revolving credit facility and $98.8 million outstanding under our term credit facility at an interest rate of 2.625%. A one percent increase in the interest rate on the borrowings outstanding under our term credit facility as of December 31, 2012 would increase our annual cash interest expense by approximately $1.0 million. Interest rates could rise for various reasons in the future and increase our total interest expense, depending upon the amounts borrowed.

Anti-takeover Measures in Our Charter Documents and Under State Law Could Discourage an Acquisition and Thereby Affect the Related Purchase Price.

We are a Delaware corporation subject to the Delaware General Corporation Law, including Section 203, an anti-takeover law. Our restated certificate of incorporation authorizes our Board of Directors to issue up to one million shares of preferred stock and to determine the price, rights (including voting rights), conversion ratios, preferences and privileges of that stock without further vote or action by the holders of the common stock. It also prohibits stockholders from acting by written consent without the holding of a meeting. In addition, our bylaws impose certain advance notification requirements as to business that can be brought by a stockholder before annual stockholder meetings and as to persons nominated as directors by a stockholder. As a result of these measures and others, potential acquirers might find it more difficult or be discouraged from attempting to effect an acquisition transaction with us. This may deprive holders of our securities of certain opportunities to sell or otherwise dispose of the securities at above-market prices pursuant to any such transactions.

None.

Our property consists primarily of drilling rigs, pressure pumping equipment and related equipment. We own substantially all of the equipment used in our businesses.

Our corporate headquarters is in leased office space and is located at 450 Gears Road, Suite 500, Houston, Texas. Our telephone number at that address is (281) 765-7100. Our primary administrative office, which is located in Snyder, Texas, is owned and includes approximately 37,000 square feet of office and storage space.

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Contract Drilling Operations — Our drilling services are supported by several offices and yard facilities located throughout our areas of operations, including Texas, Oklahoma, Colorado, North Dakota, Wyoming, Pennsylvania and western Canada.

Pressure Pumping — Our pressure pumping services are supported by several offices and yard facilities located throughout our areas of operations, including Texas, Pennsylvania, Ohio, West Virginia and Kentucky.

Oil and Natural Gas Working Interests — Our interests in oil and natural gas properties are primarily located in Texas and New Mexico.

We own our administrative offices in Snyder, Texas, as well as several of our other facilities. We also lease a number of facilities, and we do not believe that any one of the leased facilities is individually material to our operations. We believe that our existing facilities are suitable and adequate to meet our needs.

We incorporate by reference in response to this item the information set forth in Item 1 of this Report and the information set forth in Note 4 of the Notes to Consolidated Financial Statements included in Item 8 of this Report.

We are party to various legal proceedings arising in the normal course of our business. We do not believe that the outcome of these proceedings, either individually or in the aggregate, will have a material adverse effect on our results of operations, cash flows or financial condition.

Not applicable.

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PART II

Our common stock, par value $0.01 per share, is publicly traded on the Nasdaq Global Select Market and is quoted under the symbol “PTEN.” Our common stock is included in the S&P MidCap 400 Index and several other market indices. The following table provides high and low sales prices of our common stock for the periods indicated:

As of February 7, 2013, there were approximately 1,500 holders of record of our common stock.

We paid cash dividends during the years ended December 31, 2011 and 2012 as follows:

On February 6, 2013, our Board of Directors approved a cash dividend on our common stock in the amount of $0.05 per share to be paid on March 29, 2013 to holders of record as of March 15, 2013. The amount and timing of all future dividend payments, if any, are subject to the discretion of the Board of Directors and will depend upon business conditions, results of operations, financial condition, terms of our credit facilities and other factors.

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The table below sets forth the information with respect to purchases of our common stock made by us during the quarter ended December 31, 2012.

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The following graph compares the cumulative stockholder return of our common stock for the period from December 31, 2007 through December 31, 2012, with the cumulative total return of the Standard & Poors 500 Stock Index, the Standard & Poors MidCap Index, the Oilfield Service Index and a peer group determined by us. Our peer group consists of Helmerich & Payne, Inc., Nabors Industries, Ltd., Pioneer Energy Services Corp. and Precision Drilling Corp. All of the companies in our peer group are providers of land-based drilling services. Nabors Industries, Ltd. also is a provider of pressure pumping services. Bronco Drilling Company was a member of our peer group for 2011, but it was acquired by another entity in 2011 and is therefore not a member of our peer group for 2012. The graph assumes investment of $100 on December 31, 2007 and reinvestment of all dividends.

The foregoing graph is based on historical data and is not necessarily indicative of future performance. This graph shall not be deemed to be “soliciting material” or to be “filed” with the SEC or subject to Regulations 14A or 14C under the Exchange Act or to the liabilities of Section 18 under such Act.

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Our selected consolidated financial data as of December 31, 2012, 2011, 2010, 2009 and 2008, and for each of the five years in the period ended December 31, 2012 should be read in conjunction with “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and the Consolidated Financial Statements and related Notes thereto, included as Items 7 and 8, respectively, of this Report. Due to the sale of our drilling and completion fluids business in January 2010 and the sale of our electric wireline business in January 2011, the results of operations for those businesses have been reclassified and are presented as discontinued operations for all periods presented.

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Management Overview — We are a leading provider of services to the North American oil and natural gas industry. Our services primarily involve the drilling, on a contract basis, of land-based oil and natural gas wells and pressure pumping services. In addition to the aforementioned services, we also invest, on a non-operating working interest basis, in oil and natural gas properties. Prior to the sale of substantially all of the assets of our drilling and completion fluids business in January 2010, we provided drilling fluids, completion fluids and related services to oil and natural gas operators. Due to our exit from the drilling and completion fluids business in January 2010, we have presented the results of that business as discontinued operations in this Report. We acquired an electric wireline business on October 1, 2010 and sold the business on January 27, 2011. Due to our exit from the electric wireline business, we have presented the results of that business as discontinued operations in this Report.

As of December 31, 2012, we had a drilling fleet that consisted of 314 marketable land-based drilling rigs. There continues to be uncertainty with respect to the global economic environment, crude oil prices are volatile and natural gas prices remain low. Activity in our drilling business decreased in the fourth quarter of 2012 compared to the fourth quarter of 2011. In the fourth quarter of 2012, our average number of rigs operating decreased to 206, as compared to an average of 232 drilling rigs operating during the same period in 2011.

We have addressed our customers’ needs for drilling wells in the newer horizontal shale and other unconventional resource plays by expanding our areas of operation and improving the capabilities of our drilling fleet during the last several years. As of December 31, 2012, we have completed 113 new APEX^® rigs and made performance and safety improvements to existing high capacity rigs. We have plans to complete 13 additional new APEX^® rigs in 2013. In connection with the newer horizontal shale and other unconventional resource plays, we have added equipment to perform service intensive fracturing jobs. As of December 31, 2012, we had approximately 758,000 hydraulic horsepower in our pressure pumping fleet. This is a net increase of approximately 600,000 horsepower since the end of 2009. Low natural gas prices and the industry-wide addition of new pressure pumping equipment to the marketplace has led to an excess supply of pressure pumping equipment in North America.

We maintain a backlog of commitments for contract drilling revenues under term contracts, which we define as contracts with a fixed term of six months or more. Our backlog as of December 31, 2012 was approximately $1.24 billion. We expect approximately $766 million of our backlog to be realized in 2013. We calculate our backlog by multiplying the day rate under our term drilling contracts by the number of days remaining under the contract. The calculation does not include any revenues related to other fees such as for mobilization, demobilization and customer reimbursables, nor does it include potential reductions in rates for unscheduled standby or during periods in which the rig is moving, on standby or incurring maintenance and repair time in excess of what is permitted under the drilling contract. In addition, generally our term drilling contracts are subject to termination by the customer on short notice and provide for an early termination payment to us in the event that the contract is terminated by the customer. See Item 1A. Risk Factors – Fixed Term Contracts May in Certain Instances Be Terminated Without an Early Termination Payment.

For the three years ended December 31, 2012, our operating revenues from continuing operations consisted of the following (dollars in thousands):

Generally, the profitability of our business is impacted most by two primary factors in our contract drilling segment: our average number of rigs operating and our average revenue per operating day. During 2012, our

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average number of rigs operating was 221 compared to 216 in 2011 and 168 in 2010. Our average revenue per operating day was $22,540 in 2012 compared to $21,200 in 2011 and $17,670 in 2010. Our pressure pumping segment experienced an increase in large multi-stage fracturing jobs in 2011 compared to 2010; this increase includes the contribution of a pressure pumping business we acquired on October 1, 2010, which significantly expanded our pressure pumping operations into new markets in the fourth quarter of 2010. In 2012, however, margins from the pressure pumping segment were lower than in 2011. We had consolidated net income of $299 million for 2012 compared to $322 million for 2011. The decrease in consolidated net income was primarily due to higher depreciation expense.

Our revenues, profitability and cash flows are highly dependent upon prevailing prices for oil and natural gas. During periods of improved commodity prices, the capital spending budgets of oil and natural gas operators tend to expand, which generally results in increased demand for our services. Conversely, in periods when these commodity prices deteriorate, the demand for our services generally weakens and we experience downward pressure on pricing for our services. After reaching a peak in June 2008, there was a significant decline in oil and natural gas prices and a substantial deterioration in the global economic environment. As part of this deterioration, there was substantial uncertainty in the capital markets and access to financing was reduced. Due to these conditions, our customers reduced or curtailed their drilling programs, which resulted in a decrease in demand for our services, as evidenced by the decline in our monthly average number of rigs operating from a high of 283 in October 2008 to a low of 60 in June 2009. Our monthly average number of rigs operating has subsequently increased from the mid-year low of 60 in 2009 to 233 in December 2011. In December 2012, our average number of rigs operating was 205.

We are also highly impacted by operational risks, competition, the availability of excess equipment, labor issues and various other factors that could materially adversely affect our business, financial condition, cash flows and results of operations. Please see “Risk Factors” in Item 1A of this Report.

Critical Accounting Policies

In addition to established accounting policies, our consolidated financial statements are impacted by certain estimates and assumptions made by management. The following is a discussion of our critical accounting policies pertaining to property and equipment, goodwill, revenue recognition, the use of estimates and oil and natural gas properties.

Property and equipment — Property and equipment, including betterments which extend the useful life of the asset, are stated at cost. Maintenance and repairs are charged to expense when incurred. We provide for the depreciation of our property and equipment using the straight-line method over the estimated useful lives. Our method of depreciation does not change when equipment becomes idle; we continue to depreciate idled equipment on a straight-line basis. No provision for salvage value is considered in determining depreciation of our property and equipment. We review our long-lived assets, including property and equipment, for impairment whenever events or changes in circumstances (“triggering events”) indicate that the carrying values of certain assets may not be recovered over their estimated remaining useful lives. In connection with this review, assets are grouped at the lowest level at which identifiable cash flows are largely independent of other asset groupings. The cyclical nature of our industry has resulted in fluctuations in rig utilization over periods of time. Management believes that the contract drilling industry will continue to be cyclical and rig utilization will continue to fluctuate. Based on management’s expectations of future trends, we estimate future cash flows over the life of the respective assets or asset groupings in our assessment of impairment. These estimates of cash flows are based on historical cyclical trends in the industry as well as management’s expectations regarding the continuation of these trends in the future. Provisions for asset impairment are charged against income when estimated future cash flows, on an undiscounted basis, are less than the asset’s net book value. Any provision for impairment is measured based on discounted cash flows.

On a periodic basis, we evaluate our fleet of drilling rigs for marketability based on the condition of inactive rigs, expenditures that would be necessary to bring them to working condition and the expected demand for drilling services by rig type (such as drilling conventional vertical wells versus drilling longer horizontal wells

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using high capacity rigs). In connection with our ongoing planning process, we evaluated our then-current fleet of marketable drilling rigs in 2012, 2011 and 2010 and identified 36, 53 and four rigs, during each of those years, respectively, that we determined were impaired and would no longer be marketed as rigs based on our assessment of estimated expenditures to bring these rigs into condition to operate in the current environment, as well as our assessment of future demand and the suitability of the identified rigs in light of this expected demand. The components comprising these rigs were evaluated, and those components with continuing utility to our other marketed rigs were transferred to other rigs or to our yards to be used as spare equipment. The fair value of the remaining components of these rigs was estimated to be zero as there were no future cash flows expected. We also evaluate our fleet of marketable pressure pumping equipment and in 2012 identified approximately 37,000 horsepower of pressure pumping equipment that would be retired. The identified pressure pumping equipment was impaired and estimated to have no fair value as there were no future cash flows expected. The net book value of the impaired assets of $12.5 million in 2012, $15.7 million in 2011 and $4.2 million in 2010 was expensed in our consolidated statements of operations as an impairment charge.

In light of the levels of activity and revenue per operating day experienced by us and our peers in 2012, 2011 and 2010, we concluded that no triggering events occurred during these years with respect to our contract drilling segment as a whole which would indicate that the carrying amounts of long-lived assets in that segment may not be recoverable (excluding the rigs which had been removed from our marketable fleet). We also concluded that no triggering event occurred with respect to our pressure pumping segment in 2012, 2011 or 2010 (excluding the equipment that was retired discussed above). Impairment considerations related to our oil and natural gas segment are discussed below.

Goodwill — Goodwill is considered to have an indefinite useful economic life and is not amortized. We evaluate goodwill at least annually on December 31, or when circumstances require, to determine if the fair value of recorded goodwill has decreased below its carrying value. For purposes of impairment testing, goodwill is evaluated at the reporting unit level. Our reporting units for impairment testing have been determined to be the same as our operating segments. We currently have goodwill in our contract drilling and pressure pumping operating segments. We first determine whether it is more likely than not that the carrying value of goodwill is less than its fair value after considering qualitative, market and other factors. If so, then goodwill impairment is determined using a two-step impairment test. The first step is to compare the fair value of an entity’s reporting units to the respective carrying value of those reporting units. If the carrying value of a reporting unit exceeds its fair value, the second step of the impairment test is performed whereby the fair value of the reporting unit is allocated to its identifiable tangible and intangible assets and liabilities with any remaining fair value representing the fair value of goodwill. If this resulting fair value of goodwill is less than the carrying value of goodwill, an impairment loss would be recognized in the amount of the shortfall.

In connection with our annual goodwill impairment assessment as of December 31, 2012 and 2011, we determined based on an assessment of qualitative factors that it was more likely than not that the fair values of our reporting units were greater than their carrying amounts and further testing was not necessary. In making this determination, we considered the continued demand experienced during 2012 and 2011 for our services in the contract drilling and pressure pumping businesses. We also considered the current and expected levels of commodity prices for crude oil and natural gas, which influence the overall level of business activity in these operating segments. Additionally, operating results for 2012 and 2011 and forecasted operating results for 2013 were also taken into account. Our overall market capitalization and the large amount of calculated excess of the fair values of our reporting units over their carrying values and lack of significant changes in the key assumptions from our 2010 quantitative Step 1 assessment of goodwill were also considered.

We have undertaken extensive efforts in the past several years to upgrade our fleet of equipment and believe that we are well positioned from a competitive standpoint to satisfy demand for high technology drilling of unconventional horizontal wells, which should help mitigate decreases in demand for drilling conventional vertical wells that has resulted from low natural gas prices. In the event that market conditions weaken, we may be required to record an impairment of goodwill in our contract drilling or pressure pumping reporting units in the future, and such impairment could be material.

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Revenue recognition — Revenues from daywork drilling and pressure pumping activities are recognized as services are performed. Expenditures reimbursed by customers are recognized as revenue and the related expenses are recognized as direct costs. All of the wells we drilled in 2012, 2011 and 2010 were drilled under daywork contracts.

Use of estimates — The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make certain estimates and assumptions that affect the reported amounts of assets and liabilities and disclosures of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from such estimates.

Key estimates used by management include:

Oil and natural gas properties — Working interests in oil and natural gas properties are accounted for using the successful efforts method of accounting. Under the successful efforts method of accounting, exploration costs which result in the discovery of oil and natural gas reserves and all development costs are capitalized to the appropriate well. Exploration costs which do not result in discovering oil and natural gas reserves are charged to expense when such determination is made. Costs of exploratory wells are initially capitalized to wells-in-progress until the outcome of the drilling is known. We review wells-in-progress quarterly to determine whether sufficient progress is being made in assessing the reserves and economic viability of the respective projects. If no progress has been made in assessing the reserves and economic viability of a project after one year following the completion of drilling, we consider the well costs to be impaired and recognize the costs as expense. Geological and geophysical costs, including seismic costs and costs to carry and retain undeveloped properties, are charged to expense when incurred. The capitalized costs of both developmental and successful exploratory type wells, consisting of lease and well equipment, lease acquisition costs and intangible development costs, are depreciated, depleted and amortized on the units-of-production method, based on engineering estimates of proved oil and natural gas reserves for each respective field.

We review our proved oil and natural gas properties for impairment whenever a triggering event occurs, such as downward revisions in reserve estimates or decreases in expected future oil and natural gas prices. Proved properties are grouped by field and undiscounted cash flow estimates are prepared based on our expectation of future commodity prices over the lives of the respective fields. These cash flow estimates are reviewed by an independent petroleum engineer. If the net book value of a field exceeds its undiscounted cash flow estimate, impairment expense is measured and recognized as the difference between net book value and discounted cash flow. The discounted cash flow estimates used in measuring impairment are based on our expectations of future commodity prices over the life of the respective field. We review unproved oil and natural gas properties quarterly to assess potential impairment. Our impairment assessment is made on a lease-by-lease basis and considers factors such as our intent to drill, lease terms and abandonment of an area. If an unproved property is determined to be impaired, the related property costs are expensed. Impairment expense related to proved and unproved oil and natural gas properties totaled approximately $1.9 million, $3.0 million and $792,000 for the years ended December 31, 2012, 2011 and 2010, respectively, and is included in depreciation, depletion, amortization and impairment in the consolidated statements of operations.

For additional information on our accounting policies, see Note 1 of Notes to Consolidated Financial Statements included as a part of Item 8 of this Report.

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Liquidity and Capital Resources

As of December 31, 2012, we had working capital of $340 million, including cash and cash equivalents of $111 million, compared to working capital of $346 million and cash and cash equivalents of $23.9 million at December 31, 2011.

During 2012, our sources of cash flow included:

During 2012, we used $170 million to repurchase shares of our common stock, $30.3 million to pay dividends on our common stock, $233 million to repay borrowings under our revolving credit facility, $93.8 million to repay other long-term debt, $7.5 million to pay debt issuance costs and $974 million:

We paid cash dividends during the year ended December 31, 2012 as follows:

On February 6, 2013, our Board of Directors approved a cash dividend on our common stock in the amount of $0.05 per share to be paid on March 29, 2013 to holders of record as of March 15, 2013. The amount and timing of all future dividend payments, if any, are subject to the discretion of the Board of Directors and will depend upon business conditions, results of operations, financial condition, terms of our credit facilities and other factors.

On August 1, 2007, our Board of Directors approved a stock buyback program authorizing purchases of up to $250 million of our common stock in open market or privately negotiated transactions. During the year ended December 31, 2012, we purchased 4.7 million shares under the program at a cost of approximately $70.1 million. On July 25, 2012, our Board of Directors terminated the remaining authority under the 2007 stock buyback program, and approved a new stock buyback program authorizing purchases of up to $150 million of our common stock in open market or privately negotiated transactions. During the year ended December 31, 2012, we purchased approximately 5.9 million shares under the new stock buyback program at a cost of approximately $98.9 million. As of December 31, 2012, we are authorized to purchase approximately $51.1 million of our outstanding common stock under this program.

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On September 27, 2012, we entered into a credit agreement (the “Credit Agreement”). The Credit Agreement is a committed senior unsecured credit facility that includes a revolving credit facility and a term loan facility. The Credit Agreement replaced a previous senior unsecured revolving credit facility.

The revolving credit facility permits aggregate borrowings of up to $500 million outstanding at any time. The revolving credit facility contains a letter of credit facility that is limited to $150 million and a swing line facility that is limited to $40 million, in each case outstanding at any time.

The term loan facility provides for a loan of $100 million, which was drawn on December 24, 2012. The term loan facility is payable in quarterly principal installments commencing December 27, 2012. The installment amounts vary from 1.25% of the original principal amount for each of the first four quarterly installments, 2.50% of the original principal amount for each of the subsequent eight quarterly installments, 5.00% of the original principal amount for the subsequent four quarterly installments and 13.75% of the original principal amount for the final four quarterly installments.

Subject to customary conditions, we may request that the lenders’ aggregate commitments with respect to the revolving credit facility and/or the term loan facility be increased by up to $100 million, not to exceed total commitments of $700 million. The maturity date under the Credit Agreement is September 27, 2017 for both the revolving facility and the term facility.

Loans under the Credit Agreement bear interest by reference, at our election, to the LIBOR rate or base rate, provided, that swing line loans bear interest by reference only to the base rate. The applicable margin on LIBOR rate loans varies from 2.25% to 3.25% and the applicable margin on base rate loans varies from 1.25% to 2.25%, in each case determined based upon our debt to capitalization ratio. As of December 31, 2012, the applicable margin on LIBOR rate loans was 2.25% and the applicable margin on base rate loans was 1.25%. A letter of credit fee is payable by us equal to the applicable margin for LIBOR rate loans times the daily amount available to be drawn under outstanding letters of credit. The commitment fee rate payable to the lenders for the unused portion of the credit facility is 0.50%.

The Credit Agreement requires compliance with two financial covenants. We must not permit our debt to capitalization ratio to exceed 45%. The Credit Agreement generally defines the debt to capitalization ratio as the ratio of (a) total borrowed money indebtedness to (b) the sum of such indebtedness plus consolidated net worth, with consolidated net worth determined as of the last day of the most recently ended fiscal quarter. We also must not permit the interest coverage ratio as of the last day of a fiscal quarter to be less than 3.00 to 1.00. The Credit Agreement generally defines the interest coverage ratio as the ratio of earnings before interest, taxes, depreciation and amortization (“EBITDA”) of the four prior fiscal quarters to interest charges for the same period. We were in compliance with these covenants at December 31, 2012. The Credit Agreement also contains customary representations, warranties and affirmative and negative covenants. We do not expect that the restrictions and covenants will impair, in any material respect, our ability to operate or react to opportunities that might arise.

Events of default under the Credit Agreement include failure to pay principal or interest when due, failure to comply with the financial and operational covenants, as well as a cross default event, loan document enforceability event, change of control event and bankruptcy and other insolvency events. If an event of default occurs and is continuing, then a majority of the lenders have the right, among others, to (i) terminate the commitments under the Credit Agreement, (ii) accelerate and require us to repay all the outstanding amounts owed under any loan document (provided that in limited circumstances with respect to insolvency and bankruptcy such acceleration is automatic), and (iii) require us to cash collateralize any outstanding letters of credit.

As of December 31, 2012, we had $98.8 million principal amount outstanding under the term loan facility at an interest rate of 2.625% and no amounts outstanding under the revolving credit facility. We had $39.8 million in letters of credit outstanding at December 31, 2012 and, as a result, had available borrowing capacity of approximately $460 million at that date.

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On October 5, 2010, we completed the issuance and sale of $300 million in aggregate principal amount of our 4.97% Series A Senior Notes due October 5, 2020 (the “Series A Notes”) in a private placement. The Series A Notes bear interest at a rate of 4.97% per annum. We will pay interest on the Series A Notes on April 5 and October 5 of each year. The Series A Notes will mature on October 5, 2020.

On June 14, 2012, we completed the issuance and sale of $300 million in aggregate principal amounts of our 4.27% Series B Senior Notes due June 14, 2022 (the “Series B Notes”) in a private placement. The Series B Notes bear interest at a rate of 4.27% per annum. We will pay interest on the Series B Notes on April 5 and October 5 of each year. The Series B Notes will mature on June 14, 2022.

The Series A Notes and Series B Notes are prepayable at our option, in whole or in part, provided that in the case of a partial prepayment, prepayment must be in an amount not less than 5% of the aggregate principal amount of the notes then outstanding, at any time and from time to time at 100% of the principal amount prepaid, plus accrued and unpaid interest to the prepayment date, plus a “make-whole” premium as specified in the note purchase agreements. We must offer to prepay the notes upon the occurrence of any change of control. In addition, we must offer to prepay the notes upon the occurrence of certain asset dispositions if the proceeds therefrom are not timely reinvested in productive assets. If any offer to prepay is accepted, the purchase price of each prepaid note is 100% of the principal amount thereof, plus accrued and unpaid interest thereon to the prepayment date.

The respective note purchase agreements require compliance with two financial covenants. We must not permit our debt to capitalization ratio to exceed 50% at any time. The note purchase agreements generally define the debt to capitalization ratio as the ratio of (a) total borrowed money indebtedness to (b) the sum of such indebtedness plus consolidated net worth, with consolidated net worth determined as of the last day of the most recently ended fiscal quarter. We also must not permit the interest coverage ratio as of the last day of a fiscal quarter to be less than 2.50 to 1.00. The note purchase agreements generally define the interest coverage ratio as the ratio of EBITDA for the four prior quarters to interest charges for the same period. We were in compliance with these covenants at December 31, 2012. We do not expect that the restrictions and covenants will impair, in any material respect, our ability to operate or react to opportunities that might arise.

Events of default under the note purchase agreements include failure to pay principal or interest when due, failure to comply with the financial and operational covenants, a cross default event, a judgment in excess of a threshold event, the guaranty agreement ceasing to be enforceable, the occurrence of certain ERISA events, a change of control event and bankruptcy and other insolvency events. If an event of default under the note purchase agreements occurs and is continuing, then holders of a majority in principal amount of the respective notes have the right to declare all the notes then-outstanding to be immediately due and payable. In addition, if the Company defaults in payments on any note, then until such defaults are cured, the holder thereof may declare all the notes held by it pursuant to the note purchase agreement to be immediately due and payable.

We believe that our liquidity as of December 31, 2012, which includes approximately $340 million in working capital and approximately $460 million available under our $500 million revolving credit facility, together with cash expected to be generated from operations, should provide us with sufficient ability to fund our current plans to build new equipment, make improvements to our existing equipment, service our debt and pay cash dividends. If we pursue opportunities for growth that require capital, we believe we would be able to satisfy these needs through a combination of working capital, cash flows from operating activities, borrowing capacity under our revolving credit facility or additional debt or equity financing. However, there can be no assurance that such capital will be available on reasonable terms, if at all.

Commitments and Contingencies — As of December 31, 2012, we maintained letters of credit in the aggregate amount of $39.8 million for the benefit of various insurance companies as collateral for retrospective premiums and retained losses which could become payable under the terms of the underlying insurance contracts. These letters of credit expire annually at various times during the year and are typically renewed. As of December 31, 2012, no amounts had been drawn under the letters of credit.

As of December 31, 2012, we had commitments to purchase approximately $171 million of major equipment for our drilling and pressure pumping businesses.

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Our pressure pumping business has entered into agreements to purchase minimum quantities of proppants from certain vendors. These agreements expire in 2013 and 2016. As of December 31, 2012, the remaining obligation under these agreements is approximately $26.7 million, of which materials with a total purchase price of approximately $7.0 million are expected to be delivered during 2013. In the event that the required minimum quantities are not purchased during any contract year, we could be required to make a liquidated damages payment to the respective vendor for any shortfall.

In November 2011, our pressure pumping business entered into an agreement with a proppant vendor to advance, on a non-revolving basis, up to $12.0 million to such vendor to finance its construction of certain processing facilities. This advance is secured by the underlying processing facilities and other assets and bears interest at an annual rate of 5.0%. Repayment of the advance is to be made through discounts applied to purchases from the vendor and repayment of all amounts advanced must be made no later than October 1, 2017. As of December 31, 2012, advances of approximately $10.4 million had been made under this agreement and repayments of approximately $397,000 had been received resulting in a balance outstanding of approximately $10.0 million.

Trading and Investing — We have not engaged in trading activities that include high-risk securities, such as derivatives and non-exchange traded contracts. We invest cash primarily in highly liquid, short-term investments such as overnight deposits and money market accounts.

Contractual Obligations

The following table presents information with respect to our contractual obligations as of December 31, 2012 (dollars in thousands):

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Off-Balance Sheet Arrangements

We had no off-balance sheet arrangements at December 31, 2012.

Results of Operations

Comparison of the years ended December 31, 2012 and 2011

The following tables summarize operations by business segment for the years ended December 31, 2012 and 2011:

The demand for our contract drilling services is impacted by the market price of natural gas and oil. The reactivation and construction of new land drilling rigs in the United States in recent years has also contributed to an excess capacity of land drilling rigs compared to demand. The average market price of natural gas and oil for each of the fiscal quarters and full year in 2012 and 2011 follows:

Revenues and direct operating costs increased in 2012 compared to 2011 as a result of an increase in the number of operating days and increases in average revenue and direct operating costs per operating day. Average revenue per operating day increased in 2012 primarily due to increases in contractual dayrates. Average direct operating costs per operating day increased in 2012 due primarily to higher labor-related and rig mobilization costs. The increase in operating days was largely due to increased demand during the first six months of 2012 resulting from higher oil prices and the addition of newbuild APEX^® rigs into our drilling fleet. Capital expenditures were incurred in 2012 and 2011 to build new drilling rigs, to modify and upgrade our drilling rigs

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and to acquire additional related equipment such as top drives, drill pipe, drill collars, engines, fluid circulating systems, rig hoisting systems and safety enhancement equipment. Depreciation and impairment expense included approximately $5.2 million in 2012 and approximately $15.7 million in 2011 of impairment charges related to drilling equipment on drilling rigs that were removed from our marketable fleet. We removed 36 rigs from our marketable fleet in 2012 and removed 53 rigs from our marketable fleet in 2011. Significant capital expenditures incurred in recent years to add new rig capacity also contributed to the increase in depreciation expense.